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Full text of "National energy transportation: report"

^'2d Se^fon" } COMMITTEE PRINT 



NATIONAL ENERGY TRANSPORTATION 
Volume III — Issues and Problems 



REPORT 
Prepared by the 
C50NGRESSI0NAL RESEARCH SERVICE 
AT THE Request of 
Henry M. Jackson, Chairman 
COMMITTEE ON ENERGY AND NATURAL RESOURCES 

AND 

Howard W. Cannon, Chairman, 

COMMITTEE ON COMMERCE, SCIENCE, AND 
TRANSPORTATION 

UNITED STATES SENATE 




MARCH 1978 /^}--^-ff<P^^ 

PubUcation No. 95-15 ^' ' '"^^ 




Printed for the use of the Ck>imnittees on "i^^/Ain ' ' ' tiyVv \ / ' 
Energy and Natural Resources and Commerce, Science, and 'ffii^g|»rtiftw^^//' 



95th Congress 1 COMMITTEE PRINT 

2d Session / 



NATIONAL ENERGY TRANSPORTATION 
. Volume III — Issues and Problems 



REPORT 

Prepared by the 
CONGRESSIONAL RESEARCH SERVICE 

AT THE Request of 

Henry M. Jackson, Chairman 
COMMITTEE ON ENERGY AND NATURAL RESOURCES 

AND 

Howard W. Cannon, Chairman 

COMMITTEE ON COMMERCE, SCIENCE, AND 
TRANSPORTATION 

UNITED STATES SENATE 



march 1978 



Publication No. 95-15 



Printed for the use of the Ck)mmlttees on 
Energy and Natural Resources and Commerce, Science, and Transportation 



U.S. government printing office 

2<-786 WASHINGTON: 1978 



For sale by the Superintendent of Documents, U.S. Government Printing OflSce 
Washington, D.C. 20402 
Stoclt Number 052-070-04469-1 



COMMITTEE ON ENERGY AND NATI'RAL RESOURCES 



WastiiiiKtori, Chairman 
CLIFFORD P. HANSEN, Wyoming 
MARK O. HATFIELD, Orogon 
JAMES A. McCLUKE, Idaho 
DEWEY F. BARTLETT, Oklahoma 
LOWELL P. WEICKER, Jr.. Connecticut 
PETE V. DOMENICI, New Mexico 
PAUL LAXALT, Nevada 



HENRY M. JACKSON, 
FRANK CHURCH, Idaho 
J. BENNETT JOHNSTON, Louisiana 
JAMES ABOUREZK, South Dakota 
FLOYD K. HASKELL, Colorado 
DALE BUMPERS, Arkansas 
WENDELL H. FORD, Kentucky 
JOHN A. DURKIN, New Hampshire 
HOWARD M. METZENBAUM, Ohio 
SPARK M. MATSUNAGA, Hawaii 
WENDELL R. ANDERSON, Minnesota 
JOHN MELCHER, Montana 

Grenville Gausioe, staff Director and Counsel 
Daniel A. Dreyfus, Deputy Staff Director for Leginlation 
D. Michael Harvey, Chie} Counsel 
W. O. Craft, Jr., Minority Counsel 



(11) 



COMMITTEE OX COMMERCE, SCIENCE, AXl) TRANSPORTATION 



HOWARD W. CANNON, Nevada, Chairman 



W AKREN G. MAGNUSON, Washington 
RUSSELL B. LONG, Louisiana 
ERNEST F. nOLLINGS, South Carolina 
DANIEL K. INOUYE. Hawaii 
ADLAI E. STEVENSON, Illinois 
WENDELL H. P'ORD, Kentucky 
JOHN A. DI RKIN. New Hampshire 
EDWARD ZORINSKV. Nebraska 
DONALD W. RIP:GLE, Jr., Michigan 



JAMES li. PEARSON, Kansas 
ROBERT P. GRIFFIN, Michigan 
TED STEVENS, Alaska 
BARRV Gt)LDWATER. Arizona 
BOB I'ACKWOOD, Oregon 
HARRISON H. SCHMITT, New Mexico 
JOHN C. DANFORTH, Missouri 



Atbrey L. Sarvis, Staff Director and Chief Counnel 

Edwin K. IIai.i., General Counxel 
Malcolm M. B. Sterrktt, Minority Staff Director 



(IIIi 



MEMORANDUM OF THE CHAIRMEN 



To the Memhern of the Senate Committees on Energy and Natural Resources and Commerce^ Science, 
and Transportat'ion: 

This report is tlie third vohime of a three-vohiine study on the transportation of enortry resources 
in the United States. This vohiine presents descriptions and analyses of more tlum 40 issues in the energy 
transportation fiekl. Some of these are currently the subject of congressional attention, some are certain 
to come l>efore (^ongress in the future, and others are more speculative. It is our hope that the membere 
of tlie two committees will find these discussions useful both as background on the individual issues and 
as a means of obtaining an overview of current policy problems in the realm of energy logistics. 

The fii-st volume of this study was published in May 1977, and was entitled "Current Sj'stems and 
Movements."' The second volume is still in preparation, and deals with the Federal interests and respon- 
sibilities in energy transportation. 

The study is l)eing conducted at our request by the Congressional Research Service. Eighteen CRS 
staff members have contributed portions of this volume, which was coordinated by John \V. Jimison, 
analyst with the Environment and Natural Kesources Policy Division. 

Henry M. Jackson, 
Chairman, Committee on Energy 

and A'atural Resources. 
How'ARD W. Cannon, 
Chairman, Committee on Commerce, 

Science, and Transpoi'tation. 

(V) 



LETTER OF SUBMITTAL 



The Library of Congress, 
coxgressional research service, 

Washington, D.C., March U, 1978. 

Hon. Henry M. Jackson, 

Chairman, Committee on Energy and Natural Resources. 
Hon. Howard W. Cannon, 

Chairman, Committee on Commerce, Science, and Transportation. 
U.S. Senate, Washington, D.C. 

r>E.\R Sirs: I am pleased to submit herewith a i-eport entitled, ''National Energy' Transportation, 
Volume III — Issues and Problems," pre[)ared at your request by the Coufrressional Research Service. The 
followinf; stati' mcmbei-s contril)uted portions of this vohunc: Robert L. Bamberger, analyst, Environ- 
ment and Natural Resources Policy Division (FINR) ; Dr. Carl E. Hehrens, analyst, ENR; Alva M, 
Bowen, analyst, Foreign Att'aii-s and National Defense Division (FAND) ; David E. Gushee, specialist, 
ENR; John W. Jimison, analvst, ENR; Thomas E. Kane, analyst, ENR; Lawrence Kumins, analyst, 
ENR; Martin I^e, analyst, ENR; David M. Lindahl, analyst, ENR; Larry Niksch, specialist, FAND; 
Gary J. Pagliano, analyst, F]NR; Rolxirt D. Poling, legislative attorney, American Law Division; Paul 
Rothberg, analyst, Science Policy Research Division; R. E. Sullins, analyst. FAND; Louis Allan Talley, 
analyst. Economics Division: Duane A. Thompson, analyst. ENR; Dr. Stephen J. Thompson, analyst. 
Economics Division; and Howard ('seem, analyst, Economics Division. The editor and coordinator was 
John W. Jimison, analyst, ENR. Arlette Gillis, ENR, typed and prepared this volume for publication. 

I am hopeful that this volume will provide significant assistance to the members of the committees 
and am glad that you have decided to publish it as a committee print. 
Sincerely, 

Gilbert Gude, Director. 

(vn) 



Digitized by tlie Internet Arcliive 

in 2013 



littp://arcliive.org/details/energytrOOIibr 



SUMMARY OF CONTENTS 



Page 

Memorandum of the Chairmen v 

Letter of Submittal vii 

Summary of Contents ix 

Table of Contents xi 

3. Introduction 1 

3.1. Issues and Problems Related to Existing Supply Areas 3 

3.1.1. Feedstock Supply Problems of Noi-thern Tier Refinei-s 5 

3.1.2. Truck Weight and Size Limits 11 

3.1.3. Truck Fuel i:fficiencv Standards J 22 

3.1.4. Road Damage from Coal Truck Traffic 29 

3.1.5. Nuclear Shipments Safeguards 39 

3.1.6. Xuclear Materials Shipments by Rail 50 

3.1.7. Railroad Industry: Financial Health and Prospects 54 

3.1.8. Effects of Hazardous Materials Transpoiiation Regulations on the Delivery of En- 

ergy- Products 74 

3.1.9. Waterway User Charges 91 

3.1.10. Natural (ras Pipelines— The Impact of the Natural Gas Shortage on Their Future___ 102 

3.1.11. Changes in the Oil Pipeline Industry's Regulatory and Organizational Structures 125 

3.1.12. Vulnerability of Oil and Gas Pipelines to Sabotage 159 

3.1.13. A National Power (J rid 171 

3.1.14. Convei-sion of Florida Nat.ural Gas Line to Petroleum Products Transportation 182 

3.1.15. Disruption of Energy Transportation by Weather and Natural Disasters 189 

3.1.16. Eastern Coal Slurry Pipelines 196 

3.2. Issues and Problems Related to Energy from Alaska 205 

3.2.1. Disposition of West (\)ast Oil Surplus of Alaska Crude Oil 207 

3.2.2. Additional Crude Oil Pipeline Capacity in Alaska 257 

3.2.3. Jones Act Issues 260 

3.2.4. Transportation of Alaskan Coal 268 

3.2.5. Alaska Pipeline Rates and Tariffs 274 

3.2.6. The Alaska Natuial Gas Transportation Issue 283 

3.3. Issues and Problems Related to Imported Energy 313 

3.3.1. Deepwater Port Siting and Licensing 315 

3.3.2. Tanker Design and Safety Regulation 324 

3.3.3. Transportation Retiuirements of the Strategic Petroleum Reserve 333 

3.3.4. Oil Tanker Surplus 343 

3.3.5. Overseas Supply Line Vulnerability 348 

3.3.6. Natuial Gas From Mexico 364 

3.3.7. Ratification of International Transportation Conventions 377 

3.3.8. Liquefied Natural Gas: Hazards, Safety Requirements, and Policy Issues 382 

3.3.9. LPG Import Levels, Safety, and Sources 405 

3.3.10. Cargo Preference Issues 420 

3.3.11. International Pipeline Treaty ' 43O 

3.4. Issues and Problems Related to Westeni Coal Transportation " 439 

441 
460 

, , ^ - 467 

.i.4.4. Ivoiig-term ( ontracts or Rates for Railroads Hauling Coal 475 

3.4.5. Coal Transportation Impacts of Ixx^k and Dam 26 487 

3.4.6. Coal Slurry Pipelines ~ 495 

3.4.7. Coal Transportation on the Great Lakes ^ 505 

(IX) 



j-sfswes ana rrooiems Keiatecl to Westeni Coal Transportation 

3.4.1, The Sulfur Content, Btu Content, and Certainty of Development of Western Coal"'__ 

3.4.2, Expansion of Railroad Coal Movement Capacity to Probable Western Coal Markets.-, 

3.4.3, Tvocal Impact of Coal Unit Train Traffic.. .1 



X 

Page 

3.5. Other Potential Issues 517 

3.6. Summary and Analysis 529 

3.6.1. Summary and Analysis by Fuel 529 

3.6.2. Summary and Analysis by Mode 544 

3.6.3. Additional Analysis and Conclusions 555 



A 



TABLE OF CONTENTS 



Page 

Memorandum of the Chairmen v 

Letter of Submittal vii 

Sununarv of Contents ix 

Table of rontents:___' xi 

3. Introduction 1 

3.1. Issues and Problems Related to Existing Supply Areas 3 

3.1.1. Feedstock Supply Problems of Northern Tier Refiners 5 

(By David M. Lindahl) 

3.1.1.1. Backgrround 5 

3.1.1.2. Possible Actions . 7 

3.1.2. Truck Weight and Size Limits 11 

(By Rol^ert L. Baml)erger) 

3.1.2.1. ' Backgi-ound 11 

3.1.2.2. Inefficiencies Associated with Non-Uniform Gross Vehicle Weight Limits 12 

3.1.2.3. Efi'ect of Vehicle Load Limits on Movement of Spent Nuclear Fuel 16 

3.1.2.4. Opposition to and Feasibility of Heavier Weight Limits 18 

3.1.3. Tnick Fuel Efficiency Standards..' 22 

(By Robert L. Bamberger) 

3.1.3.1. Existing Regulation of Motor Vehicle Fuel Economy 23 

3.1.3.2. Flexibility of Standards foi- Heavier Vehicles 24 

3.1.4. Road Damage from Coal Tnick Traffic 29 

(By RolxMt L. l^amberger) 

3.1.4.1. ' Movement of Coal by Tnick 29 

3.1.4.2. Estimates of High\vay Inadequacy and Financial Need 33 

3.1.4.3. Policy Options 34 

3.1.5. Nuclear Shipments Safeguards __ 39 

(By Dr. Carl E. l^ehrens) 

3.1.6. Nuclear Materials Shipments by Rail 50 

(ByDr. (^arlE. Behrens) 

3.1.7. Railroad Industi-y: Financial Health and Prospects 54 

(By Dr. Stephen J. Thompson) 

3.1.7.1. Introduction 54 

3.1.7.2. Rail Coal Traffic Forecasts 57 

3.1.7.3. Railroads Other than Conrail __ 60 

3.1.7.4. Conrail 66 

3.1.7.5. Other Studies Relating to Coal Movement 67 

3.1.7.6. Mergers. Aliandonments and Intermodal Transportation; Their Effect on En- 

ergy Transportation 68 

3.1.7.7. General Energy Policy Problems 71 

3.1.8. Effects of Hazardous Materials Transportation Regulations on the Delivery of Energy 

Products 74 

(By Paul Rothberg) 

3.1.8.1. Issue Definition ^ 74 

3.1.8.2. Introduction 74 

3.1.8.3. Laws and Regulations 75 

3.1.8.4. Areas of Concern 78 

3.1.8.5. Policy Alternatives ~__ 35 

3.1.8.6. Conclusion " .39 

(XI) 



xn 

3.1. Issues and Problems Related to Existing Supply Areas — Continued Page 

3.1.9. Waterway User Charges 91 

(By Dr. Stephen J. Thompson and Louis Alan Talley) 

3.1.9.1. Introduction 91 

3.1.9.2. Background : 92 

3.1.9.3. 20 Percent Diflferential 93 

3.1.9.4. Recent I^ser Charge Impact Studies 94 

3.1.9.5. Fuel Efficiency of Competing Modes 97 

3.1.9.6. General Energy Policy Problems 98 

3.1.10. Natural Gas Pipelines — The Impact of the Natural Gas Shortage on Their Future — 102 

(By John W. Jimison) 

3.1.10.1. " Background 102 

3.1.10.2. Emergency Sales 105 

3.1.10.3. Price Deregulation 107 

3.1.10.4. Common Carriage of Natural Gas 109 

3.1.10.5. Sharing Supplies — Interpipeline Allocation and "AVheeling" of Natural Gas 115 

3.1.10.6. Spare Capacity and Depreciation of Pipeline Investment 120 

3.1.10.7. Conclusion 124 

3.1.11. Changes in the Oil Pipeline Industry's Regulatory and Organizational Structures 125 

3.1.11.1. Legislative Background 125 

(By Robert D. Poling) 

3.1.11.2. Oil Pipeline Regulation versus Gas Pipeline Regulation 136 

(By Lawrence Kumins) 

3.1.11.3. The Question of Divestiture 142 

(By Howard Useem) 

3.1.11.4. A Concluding Note 156 

(By Lawrence Kumins) 

3.1.12. Vulnerability of Oil and Gas Pipelines to Sabotage 159 

(By John W. Jimison) 

3.1.12.1. Background 159 

3.1.12.2. Areas of Vulnerability 161 

3.1.12.3. Protective Measures." — 166 

3.1.12.4. Analysis 168 

3.1.13. A National Power Grid 171 

(By Gary J. Pagliano) 

3.1.13.1. Background 172 

3.1.13.2. Present and Future Interconnections 173 

3.1.13.3. Interconnecting Authority 176 

3.1.13.4 A Central Authority and Wheeling 177 

3.1.13.5. Conclusion 1 180 

3.1.14. Conversion of Florida Natural Gas Line to Petroleum Products Transportation 182 

(By David M.Lindahl) 

3.1.14.1. Background 182 

3.1.14.2. Consumer Benefits 183 

3.1.14.3. Maritime Opposition 184 

3.1.14.4. Proceedings 188 

3.1.15. Disruption of Energy Transportation by Weather and Natural Disasters 189 

(By John W. Jimison) 

3.1.15.1. Background 189 

3.1.15.2. Petroleum Products 190 

3.1.15.3. Coal 190 

3.1.15.4. Natural Gas 193 

3.1.15.5. Electricity 193 

3.1.15.6. Earthquakes 195 

3.1.15.7. Analysis 195 



xin 



Issues and Problems Related to Existing Supply Areas— Continued rage 

3.1.16. Eastern Coal Slurry Pipelines 196 

(By John W. Jimison) 

3.1.16.1. Background 196 

3.1.16.2. Pipeline Availability 19' 

3.1.16.3. Terrain, Siting, and Sulfur Treatment 199 

3.1.16.4. Water 200 

3.1.16.5. Rights-of-Wav 201 

3.1.16.6. Rail Competition 202 

3.1.16.7. Barge Competition 203 

3.1.16.8. Conclusion 203 

3.2. Issues and Problems Related to Energy- from Alaska 205 

3.2.1. Disposition of West Coast Oil Surplus of Alaska Crude Oil 207 

(Bv David M. Lindahl) 

3.2.1.1. ' Issue Definition 207 

3.2.1.2. Backgroimd and Policy Analysis 207 

3.2.1.3. PACTEX Pipeline 211 

3.2.1.4. Xorthern-Tier-Pipeline 219 

3.2.1.5. Kitimat Pipeline 224 

3.2.1.6. Trans Mountain Pipeline 231 

3.2.1.7. Four Comers Pipeline 233 

3.2.1.8. Direct Deliveries bv Tanker 233 

3.2.1.9. Movement by Tank Car Unit Trains 241 

3.2.1.10. Exchanges and Exports 246 

3.2.1.11. Shutting in North Slope Production 251 

3.2.1.12. Summary 251 

3.2.2. Additional Crude Oil Pipeline Capacity in Alaska 257 

(Bv David M. Lindahl) 

3.2.3. Jones Act Issues 260 

(Bv Dr. Stephen J. Thompson) 

3.2.3.1. 'Background 260 

3.2.3.2. General Energy Policy Problems 265 

3.2.4. Transportation of Alaskan Coal 268 

(By John W. Jimison) 

3.2.4.1. Transportation of Alaskan Coal — Background 268 

3.2.4.2. Analysis 271 

3.2.5. Alaska Pipeline Rates and Tariffs 274 

(By Howard Useem) 

3.2.5.1. Introduction 274 

3.2.5.2. Background 275 

3.2.5.. 3. The TAPS Tariff Controversy 276 

3.2.5.4. Additional Questions 280 

3.2.5.5. Intrastate Rate Questions 281 

3.2.6. The Alaska Natural Gas Transportation Issue 283 

(Bv Garv J. Pagliano) 

3.2.6.1. ' Background 283 

3.2.6.2. The Agency Studies 286 

3.2.6.3. Canada's Decision 288 

3.2.6.4. The Joint Decision 289 

3.2.6.5. Distribution 290 

3.2.6.6. Tlie Western Leg Issue ' 291 

3.2.6.7. Financing 296 

3.2.6.8. Wellhead Pricing and End-user Pricing 302 

3.2.6.9. Guarantees 307 

3.2.6.10. Conclusion 309 



XIV 

Page 

3.3. Issues and Problems Related to Imported Energy 313 

3.3.1. Deepwater Port Siting and Licensing 315 

(By Thomas E. Kane) 

3.3.1.1. Background 315 

3.3.1.2. Analysis ' 318 

3.3.2. Tanker Design and Safety Regulation 324 

(By Martin Lee) 

3.3.2.1. ' Background 324 

3.2.2.2. Analysis 327 

3.3.3. Transportation Requirements of the Strategic Petroleum Reserve 333 

(By David M. Lindahl) 

3.3.3.1. Background 333 

3.3.3.2. Tanker Availability 336 

3.3.4. Oil Tanker Surplus 343 

(By David M. Lindahl) 

3.3.5. Overseas Supply Line Vulnerabilitv 348 

(By AlvaM.Bowen. Jr.) 

3.3.5.1. Background 349 

3.3.5.2. Analysis 3.53 

3.3.5.3. NATO War 357 

3.3.5.4. The War at Sea Scenario 362 

3.3.5.5. Summary 363 

3.3.6. Natural Gas From Mexico 364 

(By John W. Jimison) 

3.3.6.1. ' Backgroimd 364 

3.3.6.2. Gas Supply Contribution 370 

3.3.6.3. Price I 371 

3.3.6.4. U.S.-Mexican Relations 374 

3.3.6.5. Conclusion 375 

3.3.7. Ratification of International Transportation Conventions 377 

(By Larrv Niksch) 

3.3.7.1. Background 377 

3.3.7.2. Analysis 380 

3.3.8. Liquefied Natural Gas: Hazards, Safetv Requirements, and Policy Issues 382 

(Bv Paul Rothberg) 

3.3.8.1. " Introduction 382 

3.3.8.2. Existing and Expected LNG Receiving Facilities 383 

3.3.8.3. LNG Importation Policy 391 

3.3.8.4. Hazards and Safetv Concerns 393 

3.3.8.5. Siting of LNG Facilities Onshore 395 

3.3.8.6. Siting of LNG Terminals Offshore. 398 

3.3.8.7. Federal Responsibilities and Regulations 400 

3.3.8.8. Summary 402 

3.3.9. LPG Import Levels, Safety, and Sources 405 

(By John AV. Jimison) 

3.3.9. L Background 405 

3.3.9.2. Domestic Market for LPG 407 

3.3.9.3. Projections 412 

3.3.9.4. Source^s of New Imports 414 

3.3.9.5. Contraints 416 

3.3.9.6. Other Considerations 418 

3.3.10. Cargo Preference Issues 420 

(By Martin Lee) 

3.3.10. L Background 420 

3.3.10.2. Analysis 426 

3.3.11. International Pipeline Treaty 430 

(By R. E. Sullins) 

3.3.11.1. Background 430 

3.3.11.2. Analysis 433 



XV 



Page 

.{.4. Issues and Problems Related to Western Coal Transportation 439 

.'5.4.1. The Sulfur eContent, Btu Content, and Certainty of Development of Western Coal 441 

(By Duane A. Thompson) 

3.4.1.1. AVestern Surface-Minable Reserves 441 

3.4.1.2. Sulfur Content of Western Coal 443 

3.4.1.3. Federal (^oal Leasing; Policies as a Stimulus to Western Coal Development. 446 

3.4.1.4. Recent Increases in the Development of Western Reserves 448 

3.4.1.5. Projected Production From the Western States 449 

3.4.1.6. Conclusion 458 

3.4.2. E.xpansion of Raili oad Coal Movement Capacity to Probable Western Coal Markets 460 

(Bv John AV. Jimison) 

3.4.2.1. 'Background 460 

3.4.2.2. Track Capacity 462 

3.4.2.3. Financing Larger Capacity 463 

3.4.2.4. Conclusion 466 

3.4.3. Local Impact of Coal Unit Train Traffic 467 

(Bv Duane A. Thompson) 

3.4.3.1.' Background j. 467 

3.4.4. Long-term Contra<-ts or Rates for Railroads Hauling Coal 475 

(By Jolin AV. Jimison) 

3.4.4.1. " Background 475 

3.4.4.2. Long-term Contracts Possibilities 478 

3.4.4.3. Effects on Other Shippers. Other Railroads, and Other Modes 480 

3.4.4.4. Compatibility AA'ith Statute and Regulation.-I 483 

3.4.5. Coal Transportation Impacts of Lock and Dam 26 487 

(Bv Duane A. Thompson) 

3.4.6. Coal 'Slurry Pipelines 495 

(Bv John AA'. Jimison) 

3.4.6.1. ■ Background 495 

3.4.6.2. Eminent Domain 498 

3.4.6.3. AA'ater 500 

3.4.6.4. Other Factors and Conclusion 502 

3.4.7. Coal Transportation on the (xreat Lakes 505 

(By Duane A. Thompson) 

3.4.7.1. Brief Description of the Issue 505 

3.4.7.2. Background Information 505 

3.4.7.3. Bureau of Mines Assessment 506 

3.4.7.4. Corps of Engineei-s Assessment 508 

3.4.7.5. Detroit Edison Movement 508 

3.4.7.6. Through Traffic to New York 511 

3.4.7.7. Constraints and Problems 512 

3.4.7.8. Analysis and Conclusion 514 

3.5. Other Potential issues 517 

(By John AA'. Jimison) 

3.5.1. Deregulation of Certain Transportation Industries 519 

3.5.2. The Potential for Renewed Maritime Shipment of Coal on the Eastern Seaboard 519 

3.5.3. The Transportation of Alaskan North Slope Natural Gas Liquids 520 

3.5.4. Transportation of Oil and Gas Developed on the Atlantic OCS 521 

3.5.5. Transportation of Materials to Offshore Nuclear Power Plants 521 

3.5.6. Railroad-owned Coal Reserves and the Commodities Clause 522 

3.5.7. Transportation of Products from Minemouth Conversion ^ 523 

(By David E. Gushee) 

3.5.8. Liability of Barge Operators for Oil Spills 524 

3.5.9. Natural Gas Pipeline Compressor Fuel 524 

3.5.10. Spontaneous Combustion of Coal 525 

3.5.11. Natural Gas Pipeline Divestiture 525 



XVI 

Page 



.'5.6. Summary and Analysis 529 

(By John W. Jimison) 

3.6.1. Summary and Analysis by Fuel 529 

3.6.1.1. Natural Gas 1 529 

3.6.1.2. Oil . 533 

3.6.1.3. Coal 537 

3.6.1.4. Xuclear Fuels and Electricity 542 

3.6.2. Summary and Analysis by Mode 544 

3.6.2.1. Pipeline i 544 

3.6.2.2. Railroads 548 

3.6.2.3. Trucks 549 

3.6.2.4. Water Carriers 552 

3.6.3. Additional Analysis and Conclusions 655 



3 . Introduction 

This is the the third volume of a study of the movement of energy 
in the United States under the general title, "National Energy Transporta- 
tion." The first volume was published in June, 1977, entitled "Current 
Systems and Movements." The second volume, "Federal Interests and 
Responsibilities," is still in preparation. 

This volume presents descriptions and assessments of more than forty 
issues and problems which concern transportation and energy. The basic 
criteria used to select these issues was that they are now or may be over 
the remainder of the century worthy of the attention of Congress. Many 
are currently on the legislative "front burner;" others have had almost no 
prior public consideration or are frankly speculative. The treatments of 
these issues vary considerably as a result, from very detailed and analytical 
to very general and descriptive. The purpose of each of the section is 
to enable the reader to understand what the issue is, how it is related to th 
energy situation, what public actions have been taken on the issue, if any, 
and where additional information might be obtained. They are intended to 
stand on their own, and incorporate numerous cross-references. In addition, 
the concluding summary and analysis attempts to put the issues into an 
overal 1 context . 

The volume is divided into four parts, presenting the issues related 
to each of four general areas from which energy is or will be transported. 
The first section describes issues related to current energy movements 
within the United States, and potential issues related to current 
areas of domestic energy supply. 

(1) 

24-786 O - 78 - 2 



The second section focused on Alaskan energy resources as a major 
new source of energy supply. .Currently only oil is reaching the contiguous 
States from Alaskan, but natural gas and perhaps coal will follow. Sig- 
nificant transportation related problems are discussed. 

The third section deals with transportation issues concerning imported 
energy. Oil imports are already huge, but promise to grow further. Imports 
of natural gas, both in pipelines and LNG tankers and LPG present additional 
i s s ue s . 

The final area, that of western coal resources, is a major new supply 
area for U.S. energy, perhaps the only one available in the contiguous 48 
States over the next few years. Numerous issues related to transportation 
of this coal are described. 

It is clear from the issues listed that a broad view of transporta- 
tion was taken in labelling all of these "energy issues." They are all 
energy policy issues with a major transportation dimension, and incor- 
porate the sources, destinations, prices, supply and demand, and other factors 
besides the strictly logistical factor. There are a number of potential 
issues that are not addresed, mentioned in section 3.5. Of course, from 
the broadest possible perspective, every energy issue has a transportation 
dimension to some extent . Hence the issues presented in this volume are 
a selection. They were selected by the authors, the coordinator, or sug- 
gested by congressional staff or other persons knowledgeable in the energy 
area. It is hoped that, if not complete, this selection of issues will 
encompass all of those which will bring energy transportation questions 
before Congress the near-term and mid-term future. 



3 

3.1 ISSUES AND PROBLEMS RELATED TO EXISTING SUPPLY AREAS 



3.1.1. Feedstock Supply Problems of Northern Tier Refiners .*_/ 

Refiners in the Northern Tier (Washington, Montana, North Dakota, 
Minnesota, Wisconsin, and Michigan) face increasingly serious dif- 
ficulties in obtaining adequate feedstock to maintain their operations 
at current levels. This situation is a result of declining domestic 
production in those States and in other producing states that supply 
them and of the gradual Canadian phaseout of sweet (low sulfur) crude 
exports to the United States. 

3.1.1.1. Background . The 26 refineries in the Northern Tier are 
heavily dependent on Canada for their throughput with nearly half (478,000 
b/d) of their total capacity (986,000 b/d) coming from that source during 
the Department of Energy's crude-allocation base period of November 1, 
1974 to October 31, 1975. An additional 255,000 b/d was received by 
other states during that period. The importance of the Canadian phase- 
out can be seen in Table I, which shows the planned reductions in crude 
flows from Canada. These amounts are reviewed each year, in terras of 
Canadian needs, by the Canadian National Energy Board (CNEB), and they 
may be raised or lowered as circumstances warrant. 

The continuation of heavy oil exports to the United States probably 
will not substantially ease the plight of these refiners because of the 
small volumes and the limited capability of Northern Tier refiners to handle 
that type of crude oil. All Northern Tier refiners will be affected by 
the reduced volumes of feedstock from Canada, but some will feel the full 
impact much so(iner than others. The heavy crude, most of which is produced 

*/ Prepared by David M. Lindahl, Analyst, Environment and Natural Resources 
Policy Division. 



6 

in Saskatchewan, cannot be received by Montana because of a lack of pipe 
line connections to that area,. 



Table I 

Projected Canadian Crude Oil Exports to the United States (in barrels) 



Year 


Light 


Heavy 


1977 


137 ,000 


123,000 


1978 


55,000 


140,000 


1979 


20,000 


99 ,000 


1980 


1 ,000 


88,000 


1981 





77 ,000 


1982 





68 ,000 


1983 





54,000 


1984 





42,000 


1985 





32,000 


1986 





26,000 



The Department of Energy has predicted that 1978 the shortage in 
Montana could average approximately 28,600 b/d and cost the State over 
$300 million in real income. Montana produces enough crude oil for 
its own needs, but its marketing area is much larger, encompassing 
western North Dakota, Montana, Idaho, and eastern Washington. The 
Continental Oil Company refinery (52,500 b/d) at Billings will probably 
lose most of its Canadian sweet crude by 1979; the Exxon refinery 
(45,000 b/d) also at Billings and the Farmers Union Central Exchange Inc 
refinery (40,000 b/d) at Laurel will also lose much of their throughput. 
The shortfall in Montana could be as large as 31,000 b/d in 1979 and 
48,600 b/d by 1980. 



\_/ Howard M, Wilson and Patrick Crow, Pipelines Rush Projects to Move 
North Slope Oil, Oil and Gas Journal , October 31, 1977, pp. 66-67. 



7 

The shortage in Montana will also affect eastern Washington because 
it receives much of its supply by pipeline and barge from Montana. The 
shortfall in Eastern Washington could reach 9,600 b/d in 1978; 11,300 b/d 
in 1979; and 13,000 b/d in 1980. The Department of Energy has not pre- 
dicted shortages in other Northern Tier States before 1980, although 
Michigan will have no spare pipeline capacity and could be placed in a 
shortage situation by heavy demand for locally produced products. Pro- 
duct shipments into Wisconsin will probably have to increase by about 
40,000 b/d between 1977 and 1980 because refinery utilization is expected 
to decrease from 63 percent to 33 percent due to lack of feedstock. North 
Dakota faces a similar situation and will need product shipments from 
other States to offset a decline in refinery utilization from 70 percent 
in 1978 to 66 percent by 1980. The looping of the Williams Pipeline will 
probably prevent shortages in Minnesota prior to 1980, although Conoco' s 
23,500 b/d refinery at Wrenshall is scheduled to lose all of its Canadian 
feedstock by 1979 . 

3.1.1.2. Possible Actions . Exchanges of crude oil at Montreal 
for Canadian crude in the Midwest appear to be the most practical means 
of dealing with the problem of short-term basis because the refineries 
are designed to accomodate that type of crude oil (light and sweet) and 
the pipelines are in place to carry it to them. Canada has been willing 
to do this but in the past it has required that only U.S. domestic crude 
oil be swapped for Canadian domestic oil to insure that Canada would not 
be disadvantaged during oil embargo. Canada, however, has recently relented 
and is willing to exchange its light oil for "secure" imported oil, probably 



8 

from sources in the Western Hemisphere that would not likely reduce or 

cut off their exports for political reasons. Canada does require in this 

case that for the imported oil to qualify for exchange it must be delivered 

into the Lakehead Pipeline System which has a 30-day delivery lag time. 

This would permit Canadian exchange oil to be halted before the last of 

the "secure" oil could be delivered. Prior to this decision by the Canadians, 

Northern Tier refiners would commonly buy imported oil on the Gulf Coast, 

trade it for domestic crude, and then exchange that for Canadian oil. 

These exchanges of domestic crude oil amounted to only 3,000 b/d in August 

1976 but reached 67,000 b/d in June 1977. Exchanges would probably exceed 

that level very quickly if it were not for the limited pipeline capacity 

available for the trades. 

The requirements imposed by the CNEB forces the affected refiners to 

pay a pipeline tariff to deliver domestic crude to the Lakehead Pipeline 

System at Chicago plus an incentive bonus of ten cents per barrel. Most 

refiners are apparently willing to absorb this extra transportation cost 

in preference to expensive refinery modifications to handle high-sulfur 

heavy oil or to reductions inheir throughput at great costs in efficiency. 

The lack of adequate pipeline capacity in the Chicago area, however, has 

made additional shipments extremely difficult. Some exchange volumes 

have actually been reduced because of the bottleneck. Conoco, for ex- 

2/ 

ample, has been able to obtain only 8,000 b/d in this manner. The 
only immediate alternative is to ship domestic U.S. crude oil from the 
Gulf Coast to Portland, Maine for shipment through the Portland Pipeline 
to Montreal at the prcJhibitive cost of $2.00 or more per barrel. 

11 Ibid. , p. 63. 



9 

declines in the Illinois Basin and Appalachia the problem is likely to 
worsen. The spare capacity situation is shown in Table II. 

Table II 

Spare Capacity of Connecting Pipelines in the Northern Tier States 



Pipeline 


Capacity 


Seaway 


Some 


Explorer 





Explorer (Products) 


90,000 b/d 


Texoma 





Amoco (Cushing to Chicago) 





ARCO 





Capline (Gulf Coast to 

Patoka, Illinois) 





Chicap (Patoka to Chicago) 





Texaco-Cities Service 

(Patoka to Chicago) 






The Mid-Continent pipeline system is clearly inadequate to carry the 
volumes of crude oil needed to effect exchanges with Canada on the scale re- 
quired to prevent some Northern Tier refiners from running out of light, 
low-sulfur feedstock. If many of these refineries are unable to convert 
to other types of crude or to somehow locate domestic oil of satisfactory 
quality, their rate of utilization will drop precipitously and some may 
be forced to close. The problem is especially severe in winter when product 
demand is high, causing crude oil to be backed out of the pipelines in 



10 

favor of fuel oil, and when ice on the rivers prevents barges from 
supplementing deliveries by the pipelines. The limited pipeline capacity 
has even prevented some domestic exchanges from taking place. 

Small refiners, in particular, would prefer to have pipeline space 
allocated so that they could participate in additional swaps. The Depart- 
ment of Energy does not currently have the authority to allocate pipeline 
space to refiners. Those who would receive reduced volumes as a result 
of pipeline allocation could be expected to oppose such actions. Small 
refiners, particularly those with limited access to domestic crude oil 
of the type needed for their refineries, would probably benefit to the 
greatest degree because it is mc^re difficult for them to obtain pipeline 
space and because they have fewer refineries over which they can balance 
their feedstock shortages. 

Some refiners, especially those that would lose space under the 
allocation system, maintain that Federal controls are not needed as long 
as the individual shippers are pro-rated with each shipper sharing avail- 
able space on a proportionate basis. Pipeline space allocation would 
also involve reporting requirements that concern some refiners because 
of the proprietary information that would be needed by the Department 
of Energy to implement a program for pipeline space allocation. The 
Northern Tier refiners are not eager for additional governmental regu- 
lation but this is offset by their concern over the lack of throughput 
for their refineries and their desire to complete exchanges with Canada 
that have already been authorized. Allocation could conceivably double 
the 50,000-55,000 b/d currently available for exchange. 



11 

3.1.2. Truck Weight and Size Limit.s * / 

The passage of the Federal-Aid Highway Amendments of 1974 (P.L. 93-643) 
in January 1975 probably settled the issue of maximum gross vehicle weight 
limits for trucks at the Federal level for some years to come. However, 
the issue remains an important one for the trucking industry at the State 
level . 

3.1.2.1. Background . The 1974 amendments raised the gross vehicle 

weight limit for trucks on interstate highways to forty tons, or 80,000 
1/ 

pounds. Previous to the passage of the legislation, the limit had been 
73,280 pounds, dating from the passage of the first Federal-Aid Highway 
bill in 1956. A grandfather provision in the 1956 legislation allowed 
State-designated weight limits exceeding the Federal limit to stand. Otherwise, 
final designation of maximum allowable gross vehicle weight on interstate 
highways at or below the Federal limit was left to the discretion of 
each individual State. Several States, particularly in the Far West, 
permit considerably heavier loads on other primary and secondary 
roads . 

However, as of January 1, 1978, ten States have not yet adopted the 
Federal maximum weight limit or have not authorized the limit to go into 
effect at some future date. The maximum gross vehicle weight limit in these 
States remains at 73,280 pounds. The ten States are Iowa, Illinois, Indiana, 

*/ Prepared by Robert L. Bamberger, Analyst, Environment and Natural 
Resources Policy Division. 

_1/ Volume One, p. 243 of this study incorrectly notes that the current 
Federal standard is 73,280 pounds. 



12 

Missouri, Arkansas, Tennessee, Mississippi, Pennsylvania, Maryland, and 

Connecticut (see accompanying map). Seven of the ten States run in a 

band north to south through the Midwest and effectively prevent the movement 

of heavy loads across the country. The trucking industry and trade associations 

are working at the State level to raise the allowable weight limits in 

these States from 73,280 to 80,000 pounds to achieve a uniform ceiling 

throughout the Nation. 

During the energy shortages of winter 1977, nineteen States, including 
the ten above, passed emergency regulations increasing truck gross vehicle 
weight limits for the movement of fuel only. The crisis itself, of course, 
was generated by the weather and not by any State regulations concerning 
vehicle weight, and it does not appear that restrictions on gross vehicle 
weight have ever been generally responsible for fuel shortages or related 
hardship on enduse consumers. But the lack of uniformity in State weight 
regulations does result in operating inefficiencies and inconvenience 
to motor carriers which affect the movement of primary fuels and refined 
products as well as all other freight. 

3.1.2.2. Inefficiencies Associated with Non-Uniform Gross Vehicle 

Weight Limits . The absence of uniform weight regulations from State 

to State affect a high percentage of loads moving from east to west, through 

the Midwest and into New England. One tank truck carrier servicing routes 

between Texas and Maine estimates that 65% of its total loads are adversely 

affected by the lower weight limits, including nearly the entire ten percent 

2/ 

of the firm's business carrying petroleum from or into Pennsylvania. 

Ij Telephone interview with Mr. Sam Niness, Jr., Chemical Leaman Tank 
Lines, December 12, . 



13 




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14 

One carrier servicing the South estimates that 95% of its total loads are 
affected by weight restrictions. 

Except where storage facilities are limited, it appears that most 
customers served by tank truck carriers would accept the additional quan- 
tity of product that could be shipped with the higher weight limit. Where 
carriers are forced to utilize a tanker designed for a gross vehicle load 
of forty tons to carry a smaller payload , the net payload is reduced further 
since the vehicle itself is heavier and comprises a greater percentage of 

the gross load. One carrier estimated that this imposed a penalty of 1500 

4/ 

pounds on the weight of payload that could be carried. 

A traditional argument against higher gross vehicle weight limits 
has been that heavier vehicles are less safe. However, the industry con- 
tends that carrying ligher loads in vehicles designed to carry a heavier 
load results in a bumpier ride, places additional stress upon the vehicle, 
and makes the vehicle unwieldy and less safe than if the higher load were 
permit ted . 

Clearly, permitting larger loads would add to carrier revenues and 

reduce operating costs. One carrier estimated that uniform weight limits 

5/ 

would add between four and six million dollars to operating revenues. 
However, increased revenues would probably result in lower shipping charges 
per unit of product. Generally speaking, reduced operating expenses and 
charges for any service should result in some savings that can be passed 

_3/ Telephone interview with Mr. Scott Miller, Miller Transporters, Inc., 
~ December 13 , 1977 . 

4/ Ibid . 

2/ Telephone interview with Mr, Daniel O'Donnell, Coastal Industries, Inc., 
December 12, 1977. 



15 



along to consumers either in lower prices or a postponement of future 
price increases. It is especially likely that some savings from heavier 
or uniform weight limits could be passed along to consumers in instances 
where primary fuels are delivered to public utilities whose earnings are 
closely monitored. 

The potential savings in fuel costs to carriers was not a significant 
consideration in the earliest debates over gross vehicle weight limits, 
but is a more important consideration for truckers and national energy 
policy now. A study by the Stanford Research Institute estimated the gal- 
lons of diesel fuel that could be saved annually if the States below the 
Federal limit permitted loads of 80,000 pounds. Based upon vehicles of 
70,000 pounds gross vehicle weight or more which would likely operate 



at 80,000 pounds gross vehicle weight if permitted to do so, the SRI study 
estimated the following savings: 



State 


Potential Annual Savings of Diesel 
Fuel if 80,000 Pound Limit Permitted 
(gal Ions ) 


Arkansas 


4,117,647 


Connecticut 


3,308,823 


II 1 inois 


11,911,765 


Indiana 


16,323,529 


Iowa 


10,294,118 


Maryland 


10,294,118 


Mississippi 


5,073,529 


Missouri 


8,014,706 


Pennsylvania 


30,588,235 


Tennessee 


13,088,235 


Total 


113,014,705 



6^/ Chart adapted by American Trucking Association from Stanford Research 
Institute study, "Liberalization of State Regulations on Truck Sizes and 
Weights." (Draft) States which have adopted higher weight limits since 
the SRI study was completed have been omitted from tabulation above. 



16 

3.1.2.3. Effect of Vehicle Load Limits on Movement of Spent Nuclear 
Fuel . While an injunction in the courts which discouraged the shipment 
of nuclear spent fuel by railroad has been overturned, these byproducts 
continue to be transported principally by truck. Trucks seem well-suited 
to the transportation of nuclear wastes because trucks are relatively in- 
expensive to utilize and can travel conveniently from point-to-point on 
interstate highways. 

Movement of low-level wastes by trucks can generally be accomplished 
without exceeding Federal or State truck gross vehicle weight limits. How- 
ever, Federal and State vehicle load limits, and regulatory variations 
between States, do pose a problem for truck transport of spent fuel which 
requires casks of considerably more thickness and material weight than 
those utilized in the transportation of low-level wastes. According to 

7/ 

a study by the Nuclear Assurance Corporation released in September 1977, 
eleven casks for the movement of spent fuels are legally operational; 
however, only six are actually operational to any significant degree. 

A total of six designs for truck casks have been approved. The highest 
cask has a loaded weight of 50,000 pounds exclusive of the transport vehicle 
itself. The heaviest cask design, still under construction, will have 
a loaded weight of 76,000 pounds, will require a permit for interstate 
travel in some States and will not be operational at all in others. 
One other cask design with a loaded weight of 56,000 pounds might not be 

Ij Nuclear Assurance Corporation. Capability of U.S. Domestic Transporta- 
tion System for the Shipment of Radioactive Wastes. September 1977, pp. 
26-30, 125-128, B-1 . The study incorrectly indicates the Federal gross 
vehicle weight limit to be 73,280 pounds. 



17 

operational in states allowing a gross vehicle load limit of 73,280 pounds, 
but would probably be operational where the limit is 80,000 pounds. This 
particular cask design, however, has not been utilized recently. 

The casks themselves, built to Federal specifications, comprise bet- 
ter than ninety-five percent of the total loaded weight of the cask and 
spent fuel. The total weight of the spent fuel in a 50,000 pound cask 
may be only 1000 pounds. Therefore, any compromise required to reduce 
total vehicle weight to meet weight restrictions would have to be made 
in the design of the truck tractor or trailer. 

While permits can usually be obtained for overweight shipments, most 
states stipulate that an overweight permit can be issued only for shipments 
of commodities that cannot be readily dismantled or separated. In many 
instances, the state authoritites consider radioactive wastes a divisible 
commodity. Routing of spent fuel shipments can also be complicated by 
the ten States which have not adopted the Federal maximum gross vehicle 
weight limit of 80,000 pounds. Frost laws in some states which pre- 
clude the issuing of overweight permits during severe weather can restrict 
the scheduled shipment of spent fuel, however, this should not be a major 
problem because storage facilities on-site should permit some flexibility. 

Casks designed for transportation of spent fuel by rail are considerably 
heavier. Four units which are legally operable weigh seventy tons loaded; 
one larger unit weighs 98.9 tons loaded with several more of these heaviest 

Z_l Telephone interview with Mr. Jack V. Houstin, Jr., Dec. 21 , 1977 , 
Nuclear Assurance Corporation, Atlanta, Georgia. 



24-786 O - 78 - 3 



18 

units planned for construction. The casks designed for railroad transporta- 
tion will hold considerably more spent fuel. The largest railroad cask 
will accomodate 10 pressurized water reactor fuel assemblies (PWR) or 
24 boiling water reactor full assemblies (BWR) compared to the 1 PWR or 
2 BWR which can be accomodated by the largest truck cask in actual opera- 
tion currently. 

For the moment, spent fuel is stored on-site or may be moved to re- 
processing sites at Morris, 111., West Valley, N.Y., and Barnwell, S.C. 
Because reprocessing of spent fuel has not been approved, movement of 
spent fuel is relatively limited now. Whether nuclear reprocessing is 
approved at a later date or not, shipments of spent fuel will likely in- 
crease in the near future when on-site storage facilities are filled. 
One proposal under consideration in lieu of reprocessing would require 
the Federal Government to take possession of all spent fuel and store 
it in Federal repositories. Adoption of this policy alternative would 
also increase the number of spent fuel shipments. If the railroads are 
not or cannot be more fully utilized at such a time when a policy decision 
is made, shipment of spent fuel by truck may be hampered by vehicle load 
limits and variations in weight regulations between States. 

3.1.2.4. Opposition to and Feasibility of Heavier Weight Limits . 

Opposition to the higher gross vehicle weight limit in the ten States thai 
have not approved a forty-ton limit conventionally centers about the conten- 
tion that heavier vehicle loads will result in significantly higher highway 
maintenance costs. The issue of the safety of heavier loads is cited to 

9^/ For related discussion of this issue, see section 3.1.6., Nuclear 
Material Shipment by Rail. 



19 

a lesser extent. The prospects for legislation to adopt the forty ton 
limit in any State are also" subject to local conditions. In some States, 
the state highway departments are opposed to the heavier weight limit, and 
the Midwest regional chapter of the American Association of State Highway 
and Transportation Officials (AAHTO) has expressed opposition even though 
the national organization has favored uniform weight limits. 

National studies favor considerably higher weight limits than the 
current forty ton level. The Federal Highway Administration (FHA) com- 
pleted a study in 1968, not released until 1974, which argued that a 
gross vehicle weight limit of 120,000 pounds was desirable from the stand- 
point of highway economics and that no limit on gross vehicle weight was 
necessary with proper control of axle weight and spacing. Since the inter- 
state system was designed to accommodate defense vehicles weighing approx- 
imately 120,000 pounds or more, the trucking industry has contended that the 
argument that heavier loads will dramatically increase the cost of high- 
way maintenance is contradictory because the interstate system, if built 
to specifications, should accommodate heavier loads with routine maintenance. 
The FHA study calculated that the ratio of benefits to costs — reduced 
operating expense to truckers against increased highway maintenance costs 
— from heavier gross vehicle weight limits would be roughly 23 to 1 on 
the average for all highway systems. Responding to the argument that heavier 
loads would have a deleterious effect upon road conditions, the report 
noted: 

The fear on the part of many individuals and the public at large 
that increased vehicle weight limits would quickly destroy existing 
pavements is not in agreement with past experience. Axle-weight 
limits have been raised over the last 45 years from about 8,000 
to 23,500 pounds per single axel and, during this time, the number 
of heavy axle applications and their average weights applied to the 
pavements have increased. Yet over the 45 years that these increases 



20 



have been experienced, improvement and reconstruction of highways 
for this reason alone had been a gradual yearly factor. The 
highways have been financed from year to year without pinpointing 
any particular part of the financing that has resulted from increasing 
axle and gross weight limits. 

In the event that the State laws were altered to provide for 
higher axle-weight and gross weight limits, it is not likely 
that an increase in the rate of deterioration of highway 
pavements would be specifically noticed. The analysis, 
however, shows that any expected increase in the rate of re- 
constructing pavements that might result from increased 
weight limits would be many times offset by a decrease in the cost 
of highway trucking operations. 10 / 

At the time of the study's release in 1974, a cover letter from 

the FHA accompanying the study added the caveat that "any substantial 

increase in legal loads without a massive program to update, monitor, 

and maintain the highway system would create disastrous effects in 

many States." Analysts within the trucking industry believe the 

findings of the study and the posture of the FHA towards the study's 

conclusions have been inconsistent. 

The Interagency Study of Post-1980 Goals for Commercial Motor 
Vehicles supported enacting legislation to permit longer, wider and 
heavier vehicles, urging that any Federal laws "be designed to en- 
courage state uniformity, or, if necessary, be preemptive." The 
study recommed that highway use taxes be increased for heavier classes 
of commercial vehicles during a five-year transition period to defray 
costs of improvements to the highway system. 

Barring a sense of national urgency more likely to be brought on by 
considerations of national energy policy and transportation fuel economy 



10 / Federal Highway Administration. Economics of the Maximum Weight 

Limits of Motor Vehicle Dimensions and Weights. Chapter 17. (Report 
No. FHWA-RD-73-70) . 

11 / Interagency Study of Post-1980 Goals for Commercial Motor Vehicles. 
Executive Summary. July 1976, Draft, pp. 18-19. 



21 

rather than by a concern for more efficient movement of primary fuels, 
refined products and other freight, it does not seem likely that the gross 
vehicle weight limit will be increased at the Federal level in the neai — 
term. The trucking industry identifies no such effort at the Federal level, 
but will continue to push to establish the forty-ton limit nationwide. 



22 

3.1.3. Truck Fuel Efficiency Standards * / 

Many energy policy analysts believe that the greatest potential and 
flexibility for reducing national energy consumption lies within the trans- 
portation sector. Motor fuel consumption currently averages over seven million 
barrels of oil per day, or roughly forty percent of total petroleum consumption 
While passenger automobile fuel economy has improved by more than thirty 
percent since 1974, dramatic increases in the sales of smaller trucks 
for personal and commercial utilizations, and recreation vehicles indicate 
to some analysts that fuel consumption by trucks may be a critical determinant 
of future levels of total fuel consumption. In a Staff Working Paper 
on the National Energy Plan, the Congressional Budget Office noted that 

"trucks hold the key to narrowing the gap between actual and target gasoline 

1/ 

consumption in 1985." 

The Energy Policy and Conservation Act (P.L. 94-163) (EPCA), signed 
into public law in December 1975, established average fuel economy standards 
for individual manufacturer's new passenger car fleets beginning with 
model year 1978, and provided authority for the promulgation of standards 
at a later date for nonpassenger automobiles below 6,000 pounds gross 
vehicle weight, and nonpassenger automobiles and trucks between 6,000-10,000 
pounds gross vehicle weight. 

However, with the exception of private and short-haul instances, 
vehicles utilized in the transportation of energy are not affected by 
existing Federal regulations concerning motor vehicle fuel economy, and 

*/ Prepared by Robert L. Bamberger, Analyst, Environment and Natural 
Resources Policy Division. 

II U.S. Congress. Congressional Budget Office. President Carter's Energy 
~ Proposals: A Perspective. Staff Working Paper. June 1977. p. 55. 



23 

it is unlikely that any fuel economy standards affecting heavier trucks and 
conimercial vehicles will be promulgated in the near future. 

3.1.3.1. Existing Regulation of Motor Vehicle Fuel Economy . Under 
EPCA, vehicles subject to fuel economy standards are 4-wheeled vehicles 
"manufactured primarily for use on public streets, roads, and highways" 
rated at 6,000 pounds gross vehicle weight or less, or a vehicle which 
(a) is rated between 6,000-10,000 pounds gross vehicle weight, (b) is 
a vehicle for which the Secretary of Transportation determines, by rule, 
fuel economy standards are feasible, and (c) is a vehicle for which it 
is determined, by rule, that fuel economy standards "will result in sig- 
nificant energy conservation" or is a vehicle utilized on public streets, 
roads and higways as cited above. 

Virtually all truck shipment of crude petroleum or refined products 
is in vehicles with a gross vehicle weight rating exceeding the statutory 
authority of the EPCA legislation. According to the 1972 Bureau of Census 
Truck Inventory and Use Survey, fewer than 1,450 vehicles, or roughly one 
tenth of one percent of all vehicles 10,000 pounds gross vehicle weight 
or less, were designated as "tank trucks for liquids," and many of these were 
perhaps designed for the transportation of non-fuel liquids. With the 
exception of isolated short hauls, it is similarly likely that vehicular 
movements of coal by trucks exceed 10,000 pounds gross vehicle weight. It 
seems reasonable to conclude that the fuel economy of trucks and commercial 
vehicles utilized in the transportation of energy cannot be regulated 
by authority of legislation already enacted concerning motor vehicle 
fuel economy. 



24 

When the full authority of EPCA is exercised, the legislation will 
regulate the fuel economy of over four-fifths of the nation's heavier 
non-passenger automobiles and trucks. Table I provides a breakdovm of 
truck and bus sales by weight since 1970, and shows that sales of vehicles 
10,000 pounds gross vehicle weight or less have historically represented 
better than eighty percent of truck sales and, in recent years, nearly 
ninety percent. The increase in sales of vehicles between 6,000-10,000 
pounds gross vehicle weight no doubt reflects the increasing popularity 
of recreation vehicles in the last three years. 

3.1.3.2. Feasibility of Standards for Heavier Vehicles 

It is unlikely that fuel economy standards for trucks over 10,000 pound 

gross vehicle weight will be developed in the near future. One problem 

in developing such standards is that it is far more difficult to isolate a 

useful standard for measuring the fuel efficiency of larger vehicles. The 

executive summary of the Interagency Study of Post-1980 Goals for Commercial 

Motor Vehicles noted that "miles per gallon ... is a relatively meaningless 

2/ 

number unless the type of vehicle and its load are also defined." The 
task force recommended measuring fuel economy "in terms of how much (in 
weight or in volume) [a vehicle] carries for the amount of fuel used," 
but also conceded that a unit such as "ton-miles" is marginally useful 
when comparing vehicles carrying low-density freight (such as Q-tips) and 
high density freight (such as newsprint). 

Ij Interagency Study of Post-1980 Goals for Commercial Motor Vehicles. 
Executive Summary. Draft. November 1976. p. 4. 



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26 

In a more strongly-worded critique, the American Trucking Association 
has argued that ton-miles are an inappropriate measurement of truck fuel 
efficiency because ton-miles do not describe the actual service provided 
by carriers, the character of the commodity or the load carried, and do 
not measure the productivity of the vehicle. Fuel efficiency, the ATA, 
argues, cannot be measured apart from fuel use productivity, or "the 
efficiency with which resources are converted into goods and services 
... ." Ton-miles assume that "all tons or all miles are homogeneous." 
If fuel use efficiency is to address the total operation of a vehicle, 
the ATA contends, the analysis must accept that "within the trucking 
industry, and for the individual truck owner and operator, all things 
are rarely equal." 

Measuring the fuel efficiency of heavier vehicles must also account 
for other variables such as the truck's mission. A truck used principally 
in urban areas will naturally consume more fuel than one operated on 
the open highway. Additionally, the majority of trucks utilized in 
commercial service are purchased and equipped against customer specifications 
which outfit the vehicle for a particular utilization. The task force 
report noted: 

Much efficiency is built into trucks by this tailoring to the 
job, but much complication also arises when one attempts to 
characterize or "average" the national fleet or projected im- 
provements in the fleet. Attempts to standarize the national 
fleet about some "average" could destroy the service evidenced 
today and result in greater national fuel consumption . 

These facts lead to the obvious conclusion that attainment of 
fuel conservation beyond the present base can be realized only 



3^/ American Trucking Association. Comments in response to the Request 
for Information and Public Comment on DOT Docket Fe-Ol , Truck and 
Bus Voluntary Fuel Economy Improvement Program. June 24, 1975, pp. 17-20. 



27 

through careful assessment and implementation of appropriate 
methods on vehicle-by-vehicle and fleet-by- fleet bases by 
those persons most familiar with the vehicles and their 
missions. 4/ [underlining in original] 

While existing legislation could regulate the great majority of the 
truck fleet, and while it is unlikely that the fuel economy of heavier 
truck and commercial vehicles will be regulated in the near-term, the con- 
sumption of energy by heavier trucks is significant enough to warrant con- 
servation efforts. Movement of freight by trucks accounted for 14.5% of 

5/ 

transportation energy consumed in 1972, the greatest part of which was 
likely consumed by vehicles over 10,000 pounds gross vehicle weight. The 
high cost of fuel has enlisted the interest of regulated and private 
carriers in means to increase vehicle efficiency and to reduce operating 
costs. 

Greater truck fuel economy may be achieved from technological im- 
provements, increased operating efficiencies, and modifications to Federal 
and State regulations of trucking where majority opinion finds significant 
advantage. Vehicle streamlining, demand-actuated fan systems, and wind 
deflectors to reduce aerodynamic drag can achieve fuel savings of approximately 
five percent in proper applications. Utilization of radial tires, where ap- 
propriate to the truck's usage, can reduce fuel consumption by five to 
ten percent. Regulatory policy options could reduce empty mileage traveled 
by trucks, and could liberalize regulations which sometime require truckers 

4/ • Ibid. , p. 7 

5_l U.S. Department of Transportation. National Transportation: Trends 
and Choices (to the Year 2000). January 1977. Chart, p. 33. 



28 

to travel indirect routes to preserve competition. Another policy option 
would be to relax Federal and State limitation on size, weight and vehicle 
configuration . 

Federal agencies are not ignoring the potential for fuel economy 
improvement of these vehicles. Following the appearance of the task force 
report in early 1975, the Federal Energy Administration, DOT and EPA 
signed a memorandum of understanding establishing a voluntary truck and 
bus fuel economy improvement program. One goal of the program has been 
to develop a number of technical bases for developing and isolating 
a measurement of the fuel efficiency of larger vehicles, and for developing 
use cyles which describe the broad range of truck utilizations. In addition t 
generating information on fuel use characteristics of larger vehicles, 
another essential purpose of the program has been to disseminate information 
to operators of commercial vehicles and fleets so as to facilitate and 
encourage voluntary actions to safe fuel and reduce operating costs. 
The program has enlisted the cooperative efforts of motor carriers, 
trade associations, vehicles and engine manufacturers, and labor groups, 
and is under the direction of W.H. Close of the Department of Transportation. 



29 



3.1.4. Road Damage from Coal Truck Traffic * / 

Greater reliance upon coal in the next several decades will alter 
the patterns and magnitude of the transportation of mined coal, and will 
require increasing reliance on rail and truck modes of transport. Several 
States, particularly in Appalachia, are experiencing accelerated and severe 
damage to secondary and rural road systems from trucks hauling coal, and 
the problem is anticipated to become worse by 1980 and beyond. 



3.1.4.1. Movement of Coal by Truck . The Federal-Aid Highway Act 
of 1976, signed into public law as P.L. 94-280, authorized an investigation 
and study to ascertain "the need for special Federal assistance in the con- 
struction or reconstruction of highways on the Federal-aid system necessary 

for the transportation of coal or other uses" contributing toward the alleviation 

1/ 

of the national energy crisis. While only one-tenth of total coal production 
moves from the mine directly by truck to the final market, trucks "form 
a collection and distribution system which is involved in over half of all 
coal shipments," including coal transport to rail and water bulk loading 
facilities. Nearly seventy-five percent of mined coal is transported 

2/ 

by truck during some phase of its movement from the mine to the consumer. 



*/ Prepared by Robert L. Bamberger, Analyst, Environment and Natural 
Resources Policy Division. 

_1/ Completion and release of the study has been delayed due to the establish- 
ment of a Coal Transportation Task Force by the Secretary of Transportation 
in May 1977. The task force completed a draft interim report broadly 
examining coal transportation dated September 1977; release of the 
study directed by P.L. 94-280 is anticipated in early 1978. 

11 Transporting the Nation's Coal. A Preliminary Assessment report to the 
Secretary of Transportation. Coal Transportation Task Force. January, 
1978. pp. ii, II-l. 



30 

The economics of coal transportation, restrictions on gross vehicle 

weight, and the comparatively limited capacity of trucks restricts the 

advantageous utilization of trucks to short haul situations of typically 

less than fifty miles. The inherent operational flexibility of trucks 

makes them especially useful to strip mining operations where fixed loading 

3/ 

facilities are impractical due to the constant shifting of the coal face. 

Coal hauling by trucks generally bridges distances: (1) from the mine 
to the rail tipple or barge loading facility; (2) from the mine direct to 
market; or (3) from the mine to a "mine mouth" generating plant. The distance 
from the mine to the tipple is usually within five to ten miles. When last 
measured in 1969, nearly thirty percent of total coal production was moved 
by truck from the mine to the tipple. According to 1974 figures, approximately 
eleven percent of all coal produced moved directly by truck from the mine 
to the end-user, and over eighty percent of this tonnage was carried in the 

Appalachian region. An estimated ten percent of mined coal was transported 

4/ 

to generating stations near the mine mouth that same year. 

In most instances, coal haul trucks travel on local and secondary road 
systems inadequate to withstand repeated usage by heavy duty trucks, even 
where the gross vehicle weights are within posted legal limits. Where legal 
load limits are exceeded, the damage is more severe. The cost of highway 
construction, maintenance and reconstruction must currently be borne by the 
States. It is uncertain whether the individual States can muster sufficient 
financial resources to maintain the highways against sustained damage from 

V Ibid., II-3. 

kj Ibid., II-5-9. A significant percentage of coal moved from mine sites to 
mine mouth generating plants is transported in large, off-highway trucks 
which cannot negotiate standard highways and which only cross public 
thoroughfares at specified points. 



31 



SUMMARY OF COAL MOVEMENTS IN APPALACHIA BY ORIGINATING STATE, 1974 



(000 tons) 





Truck 
Only 


Truck/ 
Rail 


Truck/ 
Water 


Rail 
Only 


Water 
Only 


Other- 


Total 


Alabama 


2,598 


5,681 


2,995 


5,014 


1 ,446 


1 ,843 


19,577 




1 "5 2% 


29 0% 


15.3% 


25.6% 


7.4% 


9.4% 


100.0/ 


Eastern 


4,597 


68,530 


968 


11 ,050 






85,145 


Kentucky 


5 4 


80 5 


1 1 


13 






100 


Maryland 


835 


1 ,403 






— 




2,238 




37 3 


62.7 










100.0 


Ohio 


11 ,478 


3,666 


2,738 


14,734 


3,195 


5,538 


41 ,349 




27 .8 


8.9 


6.6 


35.6 


7.7 


13.4 


100.0 


Pennsyl vania 


18,711 


25,536 


2,116 


20,793 


13,312 


7,173 


87,641 


21 .3 


29.1 


2.4 


23.7 


15.2 


8.2 


100.0 


Tennessee 


2,343 


2,460 


754 


3,683 




- 


9,240 




25.4 


26.6 


8.2 


39.9 


_ 




100.0 


Vi rginia 


8 


29,420 


- 


7,196 


- 


- 


36,624 


<.l 


80.4 




19.6 






100.0 


West Virginia 


3,122 


25,587 


5,588 


56,424 


2,218 


5,572 


98,511 


3.2 


26.0 


5.7 


57.3 


2.3 


5.7 


100.0 


Appalachian 


43,692 


162,305 


15,137 


118,893 


20,172 


20,126 


380,325 


Region 


11.5 


42.6 


4.0 


31 .3 


5.3 


5.3 


100.0 



- Conveyor movement and mine mouth consumption. 
SOURCE: Research Triangle Institute. 



32 



increased transportation of coal by truck. One study by the University of 

Tennessee cited in hearings before a Senate subcommittee in 1976 calculated 

that a three-axle coal truck, running on a well-maintained decent highway at 

the maximum legal load limit would cause damages requiring $8000 in road 

5/ 

maintenance costs while paying only $1350 in licensing fees. 

The conclusions and recommendations of the Coal Transportation Task 
Force and other policy groups may impel Congress to consider whether 
national energy objectives may necessitate a policy response at the Fed- 
eral level to ensure the adequacy of regional highway systems to withstand 
the movement of coal by truck. The draft interim task force report notes 
that damage to these secondary and local roads is certain to grow in severity 
as annual tonnage and accumulated road mileage by trucks hauling coal in- 
crease. A significant increase of coal haulage by truck is anticipated east 
of the Mississippi, especially in Appalachia where small surface mines are 
the prevalent form of mining operation. The report considers the possibility 
that : 

Appalachia' s coal road problems could well become so severe 
as to become a bottleneck on coal production. Further, truck ton- 
nage could increase even more rapidly than expected if coal re- 
serves are developed in areas not served by the. bulk hauling 
modes. Inasmuch as there are no firm indications of railroad 
plans to build additional spur lines to serve these areas, and 
since small mine operators are unable to finance rail construction 
themselves, the burden of coal transportation in these situations 
is likely to fall predominantly on the highway mode. Also, should 
developments in pollution control equipment for coal-fired generators, 
or in legislation concerning pollution control, make it uneconomical 
to use Western coal in Midwestern or Eastern markets, a larger 
than expected share of the expansion in coal production will have 
to occur in the East with the result that the truck mode's share 



5_l U.S. Congress. Senate. Committee on Public Works. Subcommittee on Trans- 
portation. Energy Impacted Roads. 94th Congress, 2nd session. May 26, 
1976, p. 66. 



33 

of the transportation burden would likely increase in both absolute 
and relative terms. 6^/ 

Damage to the roads, however, may not be due strictly to increased 
utilization by coal haul trucks. Escalation of mining operations have 
drawn larger populations to the mining regions, increasing the per capita 
load on roads and other public and social service as well. The need to 
finance services in addition to maintenance of the highways has unfortunately 
preceeded generation of the tax revenues essential to support these 
services . 

3.1.4.2. Estimates of Highway Inadequacy and Financial Need. A study 
released by the Research Triangle Institute in November 1977 surveyed the 
effect of coal movement on highways in Appalachia, including the States 
of Alabama, Kentucky, Maryland, Ohio, Pennsylvania, Tennessee, Virginia, 
and West Virginia. The study identified 6880 miles of road, and between 

7/ 

900 to 110 bridges as inadequate to accommodate coal haul trucks in 1974. 

The study found that roughly fifty-eight percent of all coal production 
in Appalachia (roughly 221 million short tons) was carried by truck from the 
mine. Movement of coal solely by truck to its final destination varied from 
less than one percent in Virginia to a high of thirty-seven percent of total 
production in Maryland (see chart). However, on a strict tonnage basis, 
the study found that Pennsylvania moved the most coal directly by truck 
to market, followed by Ohio. Movement of coal by truck to rail distribution 
points appear to predominate in Eastern Kentucky, Pennsylvania, Virginia, 

6/ Coal Transportation Task Force, Ibid., p. 11-12. 

U An Assessment of the Effects of Coal Movement on the Highways in the 
Appalachian Region. Final Report. Research Triangle Institute, 
North Carolina State University and Appalachian Regional Commission. 
November 1977. 

24-788 O - 78 - 4 



34 

Alabama, and Maryland. Rail movement of coal predominate over transport 

by truck to rail distribution points in West Virginia, Ohio, and Tennessee. 

West Virginia moved the most coal by truck to water, and Pennsylvania moved 

8/ 

the most coal by water alone. 

Twenty-seven States reported highway needs resulting from "energy- 
related" activity in response to a survey conducted by the Federal Highway 
Administration. While Appalachian States indicated the greatest need for 
financial support to maintain coal haul roads, Illinois, Indiana, Arkansas, 
Wyoming, South Dakota, Utah and Colorado also reported highway damage from 
coal haulage. The task force found that approximately $7.3 billion, or 
seventy-six percent of the costs of "energy-related" highway improvements 
needed between now and 1985 "would be incurred in building or rebuilding 
roads used for hauling coal." Appalachia would require $6.4 billion, or 
eighty-eight percent of the estimated capital requirement for maintaining 
coal haul roads . 

3.1.4.3. Policy Options . Several options at both the State or national 
levels for providing revenue assistance to maintain or construct coal haul 
roads are under consideration. In some instances, the ultimate costs would 
be borne either by the coal mining industry, by the taxpayer, or passed through 
to the consumer. Possible options include a highway user tax, a national 
or State coal severance tax, a specific Federal-aid program, or increased 
regulation of coal hauling such as greater enforcement of vehicle load 
limits . 

8/ Ibid., p. 3-6 - 3-8. 

9/ Coal Transportation Task Force, Ibid., p. II-9. See especially 

Table II-4, p. 11-11, for specific estimates of the financial needs 
of individual States to repair highway damage from energy-related 
activities . 



35 

The Research Triangle study concludes that a general highway user tax 
on coal haul trucks would be impractical. Most jurisdictions would probably 
lack the capacity and manpower to accurately assess highway use, and 
such a tax would be unfair unless assessed according to the use of 
the roads by a given truck operator or fleet. 

Some states impose a severance tax on mined coal. Kentucky, for 

example, imposes a tax of at least fifty cents per ton, or 4.5% of the 

value of the rained coal, whichever is greater. Much of the proceeds 

of the tax have been allocated for the improvement and maintenance of 

10/ 

coal haul roads in the eastern portion of the State. 

A national severance tax is another policy option. However, the 
prospects for a national severance tax may be somewhat dimmed by passage 
of the Surface Mining Control and Reclamation Act, (P.L. 95-87), and the 
possible passage of the Black Lung Benefits Reform Act (H.R. 4544). 

P.L. 95-87 created an Abandoned Mine Reclamation Fund to be financed 
by a tax of $.35/ton on surface-mined coal and $.15/ton on coal mined under- 
ground, or ten percent of the value of the coal in the mine, whichever is 
less. The revenues would be used for reclamation. 

Passage of the Black Lung Benefits Reform Act would likely result in 
the assessment of additional taxes on mined coal. One tax schedule that 
has been considered by Congress (H.R. 5322), would impose a tax of $.50 
per ton on all underground mined coal, and a tax of $.25 per ton on surface-mined 
coal with the revenues to be used to finance a Black Lung Trust Fund. The 

L 

10 / Litigation against a State severance tax may be filed in Montana by 

Decker Coal Company and four out-of-State utilities which purchase coal 
from Decker. The utilities argue that Montana's thirty percent severance 
tax exceeds the financial burden on the State from mining operations and 
is therefore an unjust burden to interstate commerce. See Energy Daily , 
January 11, 1978, p. 2-3. 



36 

measure has passed both the House and Senate and would become effective 
upon passage of H.R. 4544 which was still in conference as of late 1977. 

Though the taxes in the bills cited above are not severance taxes 
by name, the prospects for imposing any additional taxes on mined coal may 
not be favorable. However, the passage or likely passage of these bills, 
and the use of the tax mechanism to support reclamation and provide black 
lung benefits is presumably indicative of congressional priorities. Whether 
a severance tax is imposed nationally or is left to the discretion of individua 
States, it is likely that the burden of the tax would be passed along 
to consumers. However, one advantage of a national severance tax would 
be that it would not adversely affect the price competitiveness of coal 
from one region over coal from another. 

If it is infeasible to enact a tax measure to generate revenues to 
finance coal haul road maintenance and construction, another option open 
to Congress would be to enact a specific Federal-aid highway program to 
address the problem. Passage of "program specific" highway programs, 
however, are generally hampered by the argument that such programs tax 
individuals who will not derive any benefit from the application of the 
revenues. But it may be persuasive to argue in this instance that any measure 
which contributes to an assured national energy supply benefits the entire 
population indirectly even if the direct benefit is regional. 

Another option that has been given some consideration would be to 
divert coal transport from the highway to other modes of transportation, 
such as rail conveyor or coal slurry pipeline (See 3.1.16). These modes are 
less flexible than trucks and would require a substantial movement of coal 
to justify the capital expenditure. Mode diversion is probably altogether 



37 

impractical for surface mining operations, where trucks are required for 
at least the initial movement. 

The development of other transportation modes as well as the maintenance 
and construction of highways consumes time as well as capital. In the short 
run, a lack of both lead time and money may compel officials to enforce 
local load limit regulations. "A large percentage of Appalachian roadways," 
the Research Triangle study notes, "... are definitely not capable of sustaining 
what are considered to be normal loadings (in the vicinity of 24 tons) on the 
predominant types of trucks used for coal haulages." Enforcement of load 
limits may be difficult to implement, the study observes, due to community 
economic and political considerations. Coal, as the study points out in a 
familiar phrase, "is the backbone of the local economy," and local officials 
are apt to be reluctant to enforce load limit regulations. The prospects 
for meaningful enforcement are uncertain, for while highway patrol or local 
policy officials can issue citations, local courts would be called upon 
to adjudicate any violations. 

Two states, Ohio and Pennsylvania, permit coal truckers to post a perfor- 
mance bond for the privilege of exceeding load limits along a specific route 
approved by the county engineer. However, the posting of bonds tends to 
favor larger operators or truckers who can more easily afford or absorb 

the expenditure, and the likelihood that a bond can be posted can add 

11/ 

disproportionate value to mineral deposits near major roadways. 
11/ Research Triangle Institute, Ibid., Chapter 12. 



38 

As an energy source, coal is projected to have an increasingly sig- 
nificant role in the Nation's energy future. The ability to move coal 

efficiently, the task force predicts, will be crucial to the "national 

12/ 

lifestyle and the vigor of the national economy." Because the issue 

has been addressed in congressional hearings and a study mandated by 
public law, the affected States recognize that it is a problem which 
may be relieved by national legislative initiatives. Until Congress 
has gone on record to indicate whether that body believes the movement 
of coal is a national problem requiring national solutions, it seems highly 
likely that the States may be hesitant to assume the initiative to assure 
the expeditious movement of coal by highway in the raid- to long-term. 



12/ Coal Transportation Task Force, Ibid . , p. V-4 . 



39 

3.1.5. Nuclear Shipments Safeguards* / 

The term "safeguards" is used to denote measures taken to prevent theft 

or hijacking of nuclear materials which might be used by terrorists to fashion 

1/ 

nuclear explosives or otherwise threaten public health and safety. In the 
context of transportation, this means protecting those links between steps 
in the nuclear fuel cycle in which such nuclear materials are present. 

Of the 12 steps in the complete nuclear fuel cycle (See Vol. I, p. 377ff), 
only two involve materials that could be used to make nuclear explosives, and 
those two are involved in the reprocessing of spent fuel and the recycle 
of plutonium as a nuclear fuel, which have not been initiated in the U.S. 
At the reprocessing facility, plutonium, which can be used as a weapons 
material, is separated from highly radioactive fission products in spent 
fuel, and shipped to a fuel fabrication center. There it is formed into 
pellets and incorporated into fresh fuel assemblies, to be transported to 
power reactors. During these two steps the plutonium is in a form that allows 
it to be transported into bomb-quality material with relatively minor techno- 
logical barriers. 

Elsewhere in the cycle, nuclear materials in forms usable for nuclear 
explosives are not available without high technological expertise and facilities. 
The uranium used in the Light Water Reactor (LWR) fuel cycle contains uranium 
235, which can be used for nuclear explosives, but its concentration, about 
three percent, is too low for that purpose. Increasing that concentration 

*/ Prepared by Carl E. Behrens , Analyst, Environment and Natural Resources 
Policy Division. 

\_l In an international context, safeguards also include measures to prevent 
diversion of nuclear materials for weapons use by nations as well as 
subnational groups . 



40 



to bomb quality uranium requires enrichment , a complex and expensive technology 

that could not be utilized by terrorists. Similarly, spent fuel from a reactor 

contains plutonium, but mixed with it are highly radioactive fission products. 

Separating plutonium from fission products requires elaborate precautions 

and remote handling that are considered beyond the capacity of terrorist 
2/ 

groups . 

Thus the safeguarding of nuclear materials is a significant problem 

in transportation only if reprocessing and recycle of plutonium are adopted. 

Approval of recycle by the Nuclear Regulatory Commission, and before it by 

the Atomic Energy Commission, has been a strongly debated issue. AEC in 

3/ 

1974 issued a draft environmental statement supporting recycle, but 
nothing that safeguards measures would have to be stepped up; NRC in 1976 
issued a final environmental statement on the health, safety and environmental 



Ij Of the many publications issued in recent years on the subject of nuclear 
safeguards, the following are of particular interest: 

— Leachman, Robert B. and Phillip Althoff (eds.). Preventing Nuclear Theft: 
Guidelines for Industry and Government^. New York: Praeger Publishers, 1972 

— Willrich, Mason and Theodore B. Taylor. Nuclear Theft: Risks and Safe- 
guards. Cambridge: Ballinger Publishing Co. 1974. 

Institute of Nuclear Materials Management. Proceedings, 17th Annual 
Meeting, June 22-24, 1976, Seattle, Washington. Journal of the Institute 
of Nuclear Materials Management, Vol. V. No. Ill, Fall 1976. 

— Lippek, Henry E. with C. Richard Schuller. Legal, Institutional and 
Political Issues in Transportation of Nuclear Materials at the Back 
End of the LWR Nuclear Fuel Cycle. Battelle Human Affairs Research 
Centers, Seattle, WA, Sept. 20, 1977. 

— U.S. Congress. Office of Technology Assessment. Nuclear Proliferation and 
Safeguards. New York: Praeger Publishers. 1977. 

V U.S. Atomic Energy Commission. Draft Generic Environmental Statement 

Mixed Oxide Fuel (GESMO) (Recycle Plutonium in Light-Water-Cooled Reactors) 
WASH-1327. 5 vol. August, 1974. 



41 

4/ 

aspects of recycle but deferred discussion of safeguards for a later study. 
Since issuing the 1976 document, NRC has been holding public hearings on 
recycle, but has reached no decision. In the meantime, President Carter 
has called for "indefinite deferral" of reprocessing and recycle, as part 
of his effort to discourage the use of plutonium worldwide — a policy designed 
to deal with the problem of proliferation of nuclear weapons. He has also 
urged delay in developing the Liquid Metal Fast Breeder Reactor (LMFBR) 
program, a technology which would produce plutonium much more efficiently 
than in LWR's and would be fueled exclusively by that fissionable element. 

Figure 1 and Tables 1 and 2 give a measure of the amount of material 
requiring safeguards that could be expected with recycle of plutonium in the 
LWR fuel cycle. Figure 1, a reproduction of Figure IV-A-2 of the Draft 
GESMO, is a diagram of the fuel cycle, assuming 430,000 Megawatts electric 
of nuclear generating capacity in the year 1990 (substantially higher than 
currently projected). Reprocessing of spent fuel from this number of nuclear 
plants would produce 62,000 kilograms of fissile plutonium per year, of which 
44,300 kilograms would be recycled and the rest stored. Fuel rods containing 
mixed plutonium and uranium oxide totalling 1,500 metric tons of those two 
elements would be shipped to fuel fabrication facilities, and fuel assemblies 
containing 18,300 metric tons of plutonium and uranium would be shipped 
to reactors. 

Table 1, reproduced from Table IV G-1 of the Draft GESMO, indicates 
the number and size of shipments required to meet an installed capacity of 

kj U.S. Nuclear Regulatory Commission. Final Generic Environmental State- 
ment on the Use of Recycle Plutonium in Mixed Oxide Fuel in Light Water 
Cooled Reactors. Health, Safety and Environment. NUREG-0002 . 5 Vol. 
August, 1976. 



42 



Figure I 



FUEL 

ASSEMBLIES 
13800 MTM 




SPENT FUEL 
8800 MTM 



REPROCESSING 



NATURAL 
UFg 

1450 MTU 



NATURAL 
UO2 

1450 MTU 



■ 

PLUTONIUM 
62000 Kg Pu^ 

MIXED OXIDE " 
FUEL FABRICATION 



ENRICHED UFg 
12300 MTU 





41700 Kg Puf* 



PLUTONIUM 
STORAGE/INVENTORY 



2800 CANISTERS 



ENRICHMENT 
69400 MT SWU 
(42800 US, 26600 FOREIGN) 

\ f NATURAL UFg 
71800 MTU 



RECOVERED 
URANIUM 
8600 MTU 




CONVERSION 
TO UFg 

A 




WASTE STORAGE 



HIGH-LEVEL WASTE 



U30g 

99300 ST 




URANIUM MINES 
& MILLS 

ORE 47.4 X 10° MT 



'Material Indicated In Storage May Be 
All or Largely Present Elsewhere in the 
Fuel Cycle as Material in Process 



Figure IV A-2 Annual Industry-wide Fuel Cycle Requirements for Light Water Reactors 
for About 1990 With Plutonium Recycle (AEC-OPA 1974 Projection) 

Safeguards- sensitive links are emphasized. 
Source: U.S. AEC, Draft GESMO, op. cit.. Vol. Ill, p. IV A-5. 



43 



Table I 



ST "J cc 

Q. " <I _ 

_ 2 LU 00 

d; ^ > :i 

-I e/i OC — 



u 









« 


o 


B 




«H 




rH 




4J 




9 


*-< 


O 


5 






« 




u 




« 




SB 


o 






c 






i 


1 


o 


•H 


cn 


J3 




«0 








4) 


v» 


> 




•H 








•H 




CO 




C 




« 


"35 


CO 


3 


1 


U. 


«0 




•o 


o 






« 


c 








E 


« 


a 




Shi 





> 

UJ 

_J 

OQ 
< 



t3 

< 

o = 

UJ CD 

t- Z 

< 5- 



UJ ^ CC 

13 S < 

< a. UJ 

OC X > 

UJ C/? 

> U- UJ 

<t O 

o 



»- = 5 

— UJ ^ 

I- Q. p 

S Q. > g 

< 5 cc ^ 

3 1/5 UJ 

a O. 



-J S 

m o O 

•* UJ e/3 
00 Q 2 

O o <I 

? 5 F 



O 

UJ 

a. 
> 



=5 



< O 





GC 



i 2 



o 



a S 

< UJ -J 

CC 00 

oc OJ 3 

— < u. 



(£ o 



o 
o 

(- t- 

O < 



< 
I- 
O 



O 



a. 

1 I 
o 



> 



^ " ? £ 

O p w^ 

o. - §• I 

^ i/i ^ c 

c ? "= ^ 

2 E 



C- 



■o 



c 



O 
> 



CL. 

o 



i 

u 
o 



to 

Q 



o 

CO 

:3 



0) 

u 

' O 
CO 



44 



Table 2 



I o 



O 00 

>- 5 



5^ 



o 



^ 4J 



_ 3 

> I— 

CO i ^ 
o ii. 1 
o c 



- CO 

s c 

= u 
^ (d 

= 3 

- 60 
35 « 

«« 
(0 
CO 



O o < 

£ 5 = 



rsj CD 
O 

3 ti. 



CO < 

a u. 



3 



o 5 



^ < U. Q. 



> -r _ 



rsi o 



o < 



45 

430,000 MWe with and without plutonium recycle in 1990. The amount of all 
forms of plutonium indicated in the table for shipment to fuel fabrication 
plants and to storage differs from the amount of fissile plutonium shown 
in Figure 1 because not all forms of plutonium are fissile. 

From Table 1 it can be seen that the 65 metric tonnes of plutonium 
shipped to fuel fabrication facilities per year would require about 260 
shipments; another 100 shipments would be required to ship the 26 metric 
tonnes of plutonium that would go into storage. Assuming an average ship- 
ping distance of 300 miles, this would result in a total shipping distance 
of 216,000 miles per year, half of which would consist of return trips of 
empty containers that would not require safeguarding. 

Transportation of plutonium fuel from mixed oxide fabrication plants 
to uranium fuel fabrication facilities would involve 260 shipments per year, 
with a total of 1,500 metric tonnes of mixed plutonium and uranium fuel rods. 
At the uranium fabrication plant, the mixed oxide rods would be assembled, 
with fuel rods containing only slightly enriched uranium, into fuel as- 
semblies, which would then be shipped to reactors. The fuel assemblies, 
containing the same 65 metric tonnes of plutonium, would require 2,400 ship- 
ments totalling 13,800 metric tonnes of fuel assemblies. An average ship- 
ment of 5.75 metric tonnes of fuel assemblies would thus contain about 27 
kilograms of plutonium in the form of plutonium oxide mixed with uranium 
oxide . 

The plutonium in this transportation cycle is most vulnerable in the link 
between the reprocessing facility and the mixed-oxide fabrication plant. The 
plutonium oxide is concentrated at this stage and the average shipment con- 
tains about 250 kilograms of the material. Shipments to the uranium fuel 



46 

fabrication facility would contain similar amounts of plutonium, but it would 
be mixed with uranium oxide fuel, presenting a further obstacle to its utiliza- 
tion in a nuclear explosive. Even the further dilution that takes place when 
mixed oxide fuel rods are installed in fuel assemblies and shipped to a 
reactor would not remove the danger of hijack, however, since the 27 kilo- 
grams of plutonium involved in an average shipment of mixed oxide fuel would 
represent several times the necessary amount, or critical mass, necessary 
to fashion a nuclear explosive. The separation of this material is a tech- 
nological problem that probably could be solved with relative ease by a 

5/ 

terrorist group capable of constructing an illicit nuclear explosive. 

Measures to protect commercial nuclear materials from hijacking and theft 
during transportation have not been developed in great detail, since commercial 
reprocessing and recycle of plutonium have not been approved. In fact, it 
was the lack of detailed safeguards procedures that led to the delay in 
approval of recycle when AEC issued its draft environmental statement (GESMO) 
advocating such approval. However, the Energy Research and Development 
Administration (now the Department of Energy) continues to move nuclear 
materials of its own — such as highly enriched uranium for nuclear submarine 
fuel, military nuclear weapons, and other strategic nuclear material — 
and has developed a comprehensive transportation system to carry out this 
role. Included in the system is a fleet of specially built tractor-trailers 
equipped with special armor plating, bullet-proof windows- and links to a 
high-power nationwide communications system. Escort vehicles and a special 
security force are also featured. 

5J Willrich and Taylor, op. cit., p. 12 ff. 

6^/ Brennan, CD., et al . The Threat to Licensed Nuclear Facilities. Washington 
the Mitre Corp., (MTR-7022), Sept. 1975, p. 87. 



47 

Other techniques being considered, besides eliminating some transportation 

links by locating reprocessing and fuel fabrication facilities at the same 

place [ co=location] , include contaminating plutonium fuel with radioactive 

fission products, or designing shipping containers that would allow chemical 

dilution and contamination of the plutonium in the event of a hijack 
7/ 

at tempt . 

The Draft GESMO data presented in Table were computed according to 
the assumption that spent fuel would be reprocessed whether or not recycle 
was carried out. By the time the Final GESMO was issued, another option 
was considered; disposal of spent fuel without reprocessing. The alternatives 
considered in the Final GESMO included the no-reprocessing, no-recycle option; 
reprocessing with recycle of uranium but not of plutonium, and recycle of 
both uranium and plutonium. Table 2, reproduced from Table IV G-1 of the 
Final GESMO, indicates the cumulative total number of shipments for these 
three options through the year 2000, at which time 507,000 MWe of nuclear 
-capacity were assumed to be on line. No shipments of plutonium were shown 
in the uranium-recycle-only case, which assumed that the plutonium would 
be stored at the reprocessing facility site. 

Resolution of the question of recycle of plutonium, and with it the 
need for safeguarding commercial shipments of special nuclear material, will 
probably lie with the Congress and the Executive Branch. Although NRG has 
authority to approve recycle under the Atomic Energy Act as now written, it 
seems unlikely the Commission would do so in the face of President Carter's 
policy, addition to policy aspects that are outside NRC' s range of interests 
— such as the Administration's efforts to limit the worldwide proliferation 

U Institute of Nuclear Materials Management, op. cit., p. 222. 



48 

of nuclear weapons by abandoning domestic use of plutonium — economic factors 
will also enter into the decision by industry and Government to commercialize 
plutonium recycle and plutonium breeder reactors, and these economic factors 
will be strongly influenced by national energy policy. 

Commercial reprocessing, even if approved, will depend on the economics 
of the technology compared to the present uranium-only LWR fuel cycle. Three 
attempts have been made so far to begin commercial reprocessing and 
recycle, and all three have been abandoned. A small pilot plant operated 
for several years at West Valley, NY, and was shut down in 1972 for 
expansion and improvement, but the builder has since dropped the project 
because of escalating costs and licensing difficulties. A reprocessing 
facility at Barnwell, S.C., has been almost completed, but is unlikely 
to operate in view of the deferral of recycle announced by the Administration. 
A third plant, at Morris, XL, was designed to use an advanced technology 
which proved to be unworkable, and that project also has been abandoned. 
In light of these experiences, it seems unlikely that commercial reprocessing 
will be economically viable as long as uranium resources are adequate 
to support the present cycle. 

When nuclear power was expected to expand extremely rapidly, as in 
the years preceding the Arab oil embargo, the general assumption was that 
uranium for LWR's would begin to be scarce toward the end of this century. 
Adoption of the Carter Administration's energy policy, which emphasizes 
conservation and reduced growth in energy consumption, and classifies nuclear 
power as a "lower-priority energy source," could mean that these uranium 
reserves could last considerably longer. The President has asserted that 
"a viable and economic nuclear power program can be sustained without ... 



49 

8/ 

reprocessing and recycle," and that "there is no need to enter the plutonium 
age by licensing or building a fast breeder reactor" such as the LMFBR de- 
monstration plant at Clinch River, TN. 

Thus the Congressional role in determining the future of plutonium 
recycle, and with it the problems of safeguarding nuclear materials in 
transit, will lie primarily in its actions regarding national energy 
policy, and policy on nuclear power. These actions will determine 
the economic factors that will influence commercial pressure to adopt 
recycle and commercialize plutonium breeder technology. 

Conversely, the question of safeguards will continue to be a factor 
in determinination of energy policy in general , and of policy in developing 
nuclear technology. The role of nuclear power in the national energy picture 
is already significant, and can be expected to grow in light of the continuing 
crisis over imported oil and diminishing production of natural gas. The 
question of plutonium use in the nuclear fuel cycle is one of the most 
controversial of all the debates concerning nuclear power. 



8i/ Statement by President Carter on Nuclear Power Policy, April 7 , 1977 . 
9^/ President Carter's Address to Congress on the National Energy Program, 

24-786 O - 78 - 5 



50 

3.1.6. Nuclear Materials Shipments by Rail* / 

Most shipments of nuclear materials are carried out by truck at 
present, and this mode is expected to be preferred in the future. How- 
ever, for two links in the nuclear fuel cycle — transportation of spent 
fuel, and of high-level radioactive waste — rail transport may be prefer- 
able, since some of the containers for these materials are massive enough 
to cause problems with weight limits on highways (See Section 3.1.2.). 

Few shipments of spent fuel, and no shipments of commercial high- 
level radioactive waste, are currently taking place. This is because 
new policies concerning the reprocessing of spent fuel, and the consequent 
production of high-level wastes, are in the process of formulation. The 
Carter Administration has called for the deferral of commercial reproces- 
sing, and has proposed instead that the Government take possession of spent 
fuel and store it in temporary repositories. In response to the uncertainty 
regarding the back end of the nuclear fuel cycle, many reactor operators have 
begun to expand the capacity of the spent fuel storage facilities at the 
reactor sites, making it possible to defer the date on which spent fuel 
must be transported. Another possible solution to lack of on-site storage 
capacity is shipping the fuel to nearby reactor sites where storage is avail- 
able. A third possibility is storage at one of the three facilities that 
were designed fcr fuel reprocessing. The General Electric plant, at Morris, 
IL . , is already storing some spent fuel from reactors whose owners had con- 
tracted for reprocessing services before the company abandoned plans to 
operate the facility because of technical problems. Some further storage of 

*/ Prepared by Carl E. Behrens , Analyst, Environment and Natural Resources 
Policy Division. 



51 

this type is planned. Spent fuel is also stored at the Nuclear Fuel Services 
plant at West Valley, NY. However, NFS has abandoned plans to operate that 
facility and expects to turn the site over to the State of New York, which 
has not expressed interest in opening the facility for further storage of 
spent fuel. The third reprocessing facility. Allied General Nuclear Service 
Co . ' s Barnwell, SC, plant, has not been licensed to receive spent fuel, and 
none is stored there. AGNS has not expressed interest in opening the facil- 
ity for spent fuel storage until the future of the plant is further clarified. 

By using these alternative methods, reactor operators can be expected to 
deal with spent fuel on a short-term basis with relatively little need for 
transportation. A survey of reactors in operation, under construction, or 
planned indicates that most reactors will have sufficient storage capacity 

to avoid shipments of spent fuel, other than to nearby reactors, before the 
1/ 

mid-1980' s . 

The major advantage of rail shipment of spent fuel is that fewer trips 
would be required, because of the greater weight that could be handled by rail- 
borne shipping casks. For a typical 1000-megawatt reactor, 27-31 metric 
tonnes of fuel, about one-third of its fuel load, are replaced each year. 
Once the on-site storage capacity is filled, this amount would have to be 
transported to another location. Rail transportation would require 6-10 



_!/ Nuclear Assurance Corp. Capabilities of U.S. Domestic Transportation 
Systems for the Shipment of Radioactive Wastes. (Prepared for the 
U.S. Energy Research and Development Administration.) Y/OWI/SUB-77/ 
22330. NACC-7715. September, 1977. 
Appendix E. Fuel Discharge Data. 



52 



shipments per year for this amount; shipments by legal-weight truck would re 

2/ 

quire 40-60 trips. Even in some cases where there is no on-site rail 
access — which is the case for 52 of 192 operating or planned reactors 
surveyed in the NAC study — a prefered mode may be shipment by over- 
weight truck to a nearby rail center. 

The major obstacle to the use of rails to ship spent fuel has been 
reluctance by the railroads to engage in the traffic, which, because of 
its relatively low volume and consequent low revenue does not appear to 
compensate for what the railroads perceive as a high-risk material . 
Because of this position, three actions are before the Interstate Commerce 
Commission that restrict rail transport of spent fuel. In two actions, 
one by the Missouri-Kansas-Texas Railroad and the other by the Eastern 
Railroads, spent fuel and radioactive waste have been "flagged out", 
meaning that the railroads refuse to transport it as common carriers. If 
upheld by the ICC, the railroads could either refuse to transport the 
material at all, or could provide specialized transportation service under 
negotiated contract. In the third action, by the Southern and Western rail- 
roads, spent fuel and radioactive waste have not been flagged out; these 



Ij Lippek, Henry E., with C. Richard Schuller. Legal, Institutional and 

Political Issues in Transportation of Nuclear Materials at the Back End 
of the LWR Nuclear Fuel Cycle. Battelle Human Affairs Research Centers 
Seattle: Sept. 30, 1977. 

Zj Nuclear Assurance Corp. op.cit.. Appendix D. 

hj Like many other aspects of nuclear power, the risk of transportation of 
spent fuel is highly controversial. See Lippek, op.cit., pp. 5-1 ff. 
The NAC study places the source of railroad opposition in their major 
interest in the transportation of coal: "It would appear that the 
railroads' efforts to roadblock rail transport of radioactive materials 
are primarily directed towards increasing coal usage by adding another 
impediment to the use of nuclear power." Nuclear Assurance Corp., op. 
cit . , p . 33 . 



53 

railroads have asked permission to require single-use trains at special 
tariffs and with certain routing and handling restrictions. 

The ICC has not reached a final decision in any of these cases, al- 
though initial decisions by the Commission's Administrative Law Judge 

5/ 

hearing two of the cases were against the railroad position. The 
Commission in August, 1977, issued an Environmental Impact Statement on 
the question of requiring special trains as opposed to regular tjrains. Its 
conclusion was that special trains would result in slightly higher radiological 
and nonradiological environmental impacts in normal operation, but would de- 
crease the environmental risk from the radiological standpoint under accident 
conditions. In all cases, however, the ICC concluded that "the incremental 

environmental impact of special trains as opposed to regular trains is very 
7/ 

small." 

Congressional action in the question of transportation of nuclear material 
by train does not appear to be required at the present time. In the first 
place, the need for rail transport is expected to be quite low for the very 
near future at least. Secondly, the question is currently before the ICC, 
whose decision is subject to appeal in the Federal court system. 

Nevertheless, the possibility that relatively large amounts of highly 
hazardous radioactive material may in the future be transported by rail 
should probably be monitored by the Congress so that it may be informed of 
the factors involved in case action becomes advisable. 

5/ Lippek, op. cit . , pp. 5-2, 5-7. 

6^/ U.S. Interstate Commerce Commission. Final Environmental Impact State- 
ment. Transportation of Radioactive Materials by Rail. Washington. 
August 23, 1977. 

y Ibid. , p. i. 



54 

3.1.7. Railroad Industry: Financial Health and Prospects */ 

3.1.7.1. Introduction . This section discusses the financial 

health and prospects of the railroad industry as they relate to the ability 

of the railroads to transport more coal. For a more specific discussion 

of railroad expansion of capacity to carry western coal see section 3.4.2 

and for a more specific discussion of coal slurry pipelines as an alternative 

to railroads for transporting western coal, see section 3.4.6. 

For several decades the railroad industry has been in a state of 

V 

decline. Ton-miles of rail traffic have not declined but neither 
have they grown nearly so fast as the economy has grown, nor so fast 
as the growth in ton-miles carried by trucks, barges and pipelines 
(reference 13, pp. 146-156). Furthermore, much of the more profit- 
able traffic, consisting of higher priced, more processed goods (gen- 
erally called "merchandise freight"), has shifted to trucks. Passen- 
ger traffic has declined, from more than 75 percent of all intercity 
passenger-miles provided by common carriers in 1929, to three percent 
in recent years (reference 13, pp. 155-156). Once considered to be 
a blue chip investment, rail stock has become so unattractive that ob- 
taining funds by issuing new equity shares has become impracticable 
for most railroads. As a result, debt financing in the form of equip- 
ment trust certificates has become an increasingly large proportion 

*/ Prepared by Dr. Stephen J Thompson, Analyst in Transportation, Economics 
Division . 

1/ A ton-mile is a convenient measure of traffic volume. It means one 
ton carried one mile. 



55 

of rail capitalization. Equipment trust certificates essentially are 
chattel mortgages backed by specific rail cars and locomotives which 
can be repossessed and sold if the obligations of the certificate are 
not met. Equipment leasing by the railroads from financial intermedi- 
aries has also become popular, as has ownership of rail cars by shippers 
Equipment trust certificates and leasing from intermediaries raise the 
fixed costs of railroad operations thus Jiaking railroads even more vul- 
nerable to severe financial pressures as a result of recessions in the 
economy. Also contributing to the railroads' inability to reduce ex- 
penditures when there is a downturn in traffic is the property tax 
liability resulting from owning their own rights-of-way, and the need 
to repair and maintain the rights-of-way. 

There are a number of significant reasons for the long decline of 
railroads. One of the most significant reasons is the construction of 
a vast network of roads and highways accompanied by the development of 
Hffutomobiles , buses and trucks. Airlines have taken over the largest 
share of intercity passenger traffic carried by common carriers, and 
oil pipelines and barges have taken over a large share of bulk traffic. 

As rail passenger traffic declined, the railroads' financial health 
was affected, since railroads were required to continue to provide un- 
profitable service until reduced service, and finally, total discontin- 
uance was authorized on each specific route segment by the Interstate 
.Commerce Commission (ICC). It was not until 1970 that the National 
Railroad Passenger Corporation (Amtrak) was created, relieving most rail 
roads of the responsibility of providing rail passenger service at their 
own expense. 



56 

Similarly, as a large proportion of railroad trackage, usually branch 
lines located in rural areas, became unprofitable as a result of decli- 
ning traffic and rising operating and maintenance costs, railroads could 
not abandon the line until each specific segment was approved for aban- 
donment by the ICC. Rural communities strongly resist rail abandonments, 
feeling that such abandonments hamper their chances for economic devel- 
opment, and sensing, rightly or wrongly, that abandonment means increased 
isolation from other parts of the country. 

Coupled with the problem facing rail management of passenger service 
discontinuance and light-traffic-density line abandonment, was an inability 
to adequately adjust rail rates to the changing competitive situation. For 
example, as discussed elsewhere in this report, rate contracts with shippers 
cannot be for periods of more than one year. When railroads developed a 
significantly larger car for grain shipments, the ICC would not, for several 
years, allow a reduction in rail rates in proportion to the reduced costs 
of handling the traffic in these cars. Even now, railroads generally may 
not charge rates that are below the variable costs of competing modes even 
though the proposed rates would more than cover rail variable costs and thus 
make a contribution to help offset rail fixed costs. So far, the 4R Act 
(Railroad Revitalization and Regulatory Reform Act of 1976) has had a neg- 
ligible impact on this situation and some observers attribute it to the 
standards set by the ICC for determining on which traffic the railroads 
possess market dominance. 

Labor rules often restrict the ability of rail management to improve 
the efficiency of its operations as a way to become more price compet- 
itive with trucks and barges. 



57 

All of these factors have contributed to the presently weak financial 
condition of the railroad industry, generally. Thus, it is natural that 
the public, and policy makers in particular, are concerned about whether 
the railroads are in a position to expand their output at a rate sufficient 
to transport the expected increases in coal production. 

3.1.7.2 Rail Coal Traffic Forecasts . The importance of railroads in the 
domestic transportation of coal is illustrated by the fact that railroads carry 
more coal than any other mode of transportation. In addition, railroads 
carry significant amounts of petroleum products, especially LPG, and nuclear 
fuel materials. In the future, railroads will be expected to carry much 
additional coal, especially western coal, as well as to expand service in 
transporting eastern coal and other fuels. The railroads' capacity to meet 
these challenges will depend upon the financial health of the coal-carrying 
railroads, other demands on these railroads, and the Federal Government's 
policies in regulation and promotion, or perhaps even outright participation. 

The rail share of coal traffic in 1975 was 65 percent of the total 
U.S. coal production, as shown in Table 1. The Carter Administration's 
National Energy Plan (NEP) seeks to achieve annual coal production of 
1.2 billion tons by 1985, up from 665 million in 1976. The General Ac- 
counting Office (GAO) , in two recent reports (July 25 and September 22, 
1977, references 10 and 11) stated that achieving 1.2 billion tons of 
annual output by 1985 is highly unlikely, and that it will be very dif- 
ficult to achieve as much as one billion tons annually by 1985. For 
analytical purposes, GAO selected two energy growth scenarios represen- 
ting possible high and low energy demand ranges based on a Bureau of 



58 

Mines (BoM) forecast for the high estimate and an Edison Electric 
Institute (EEI) forecast for the low estimate. GAO expects energy 
demand to fall somewhere between the two estimates and assumes that 
the rail share of coal traffic will remain unchanged. The three 
scenarios are shown in Table 1. The Bureau of Mines estimate would 







(million 

1975 


tons ) 


1985 






2000 


Mode 


Actual 


Percent 


EEI 


BoM 


NEP 


EEI 


BoM 


Rail 


418 


65% 


503 


637 


780 


608 


1 ,023 


Water 


69 


11 


83 


106 


132 


101 


170 


Truck 


79 


12 


95 


120 


144 


115 


193 


Mine-mouth use 


74 


11 


89 


113 


132 


107 


181 


y 
















Other 


8 


1 


9 


12 


12 


11 


19 




648 


100% 


779 


988 


1 ,200 


942 


1,586 



Source: Reference 11, page 5.6 
1/ 

Includes slurry pipelines. 



yield a 52 percent increase in rail coal traffic by 1985 and more than 
a 100 percent increase by the year 2000, as compared to 1975. A gradual 
increase to reach these goals in rail coal traffic would require an av- 
erage annual increase of less than five percent from 1975 to 1985 and an 
average annual increase of less than four percent from 1985 to 2000. If 
the higher, 1985 goal of the Administration's National Energy Plan is 
met and railroads continue to carry the same proportion of coal that 



59 



they carried in 1975, rail traffic would increase to 780 million tons 
in 1985, or an average annual increase of less than seven percent. 

Substantial growth in coal traffic is thus expected. Most of this 
growth is expected to take place in the West, but, as shown in Table 2, 
the eastern and southern rail districts also are expected to have major 
increases in traffic. The eastern and southern rail districts currently 



TABLE 2 . Projected Coal Traffic By Rail District 



Total Rail Traffic 

Percent increase in 

y 1974 1980 each district 

Rail District million tons % million tons % (1980 compared with 1974) 



Eastern 


195 


52 


.6% 


288 


39 


.8% 


48% 


Western 


66 


17 


.8 


279 


38 


.5 


323 


Southern 


110 


29 


.6 


157 


21 


.7 


43 


Total 


371 


100 


.0 


724 


100 





95 



Source: U.S. Department of Transportation. Transportation Systems Center 
survey of railroads as contained in the September 22, 1977 GAO 
report, page 5.6. (Reference 11) 

1/ 

The eastern rail district consists of all States north of Kentucky and 
North Carolina and east of the Mississippi River. The southern district 
consists of all other States east of the Mississippi River. The western 
district consists of all States west of the Mississippi River. 



carry the largest amount of coal. Because of the generally poor financial 
condition of the rail industry and the problems Conrail is having, sig- 
nificant doubt has been expressed in some quarters about the ability of 



60 

the railroads to handle the anticipated substantial growth in coal traf- 
fic. 

The top 15 coal-carrying railroads are listed in Table 3, along 
with various data about their financial health and coal-carrying capacity. 
The Penn Central became bankrupt in 1970 and has now become part of the 
Consolidated Rail Corporation (Conrail). Conrail began operations on 
April 1, 1976. None of the other railroads included in the table are 
bankrupt although the Illinois Central Gulf and the Chicago and North 
Western are not financially strong. According to three recent reports 
produced by the Federal Government (references 8, 9 and 11) the ability 
of Conrail to handle the anticipated growth in coal traffic is different 
from that of the other railroads which carry most present and forecasted 
coal production. Thus, Conrail will be discussed separately from the other 
railroads. 

3.1.7.3 Railroads Other than Conrail . Public concern about the financial 
health of the railroad industry was heightened recently with the bankruptcy of 
the Chicago, Milwaukee, St. Paul and Pacific Railroad (Milwaukee Road) in 
December, 1977. This was the second large railroad outside the Northeast 
and Midwest to become bankrupt in recent years, and the first having operations 
reaching all the way to the Pacific Coast. The Chicago, Rock Island and 
Pacific Railroad Company (Rock Island), a carrier in the Midwest, went into 
bankruptcy in 1975 after a merger proposal remained unsettled before the 
ICC for more than a decade. 

The Rock Island serves 13 mid-continent States bordered by Minnesota on 
the north, Texas and Mississippi on the south, Illinois on the east and 



61 



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62 

Colorado and New Mexico on the west. It carries coal westward, connecting 
with other rail lines for destinations in California and elsewhere. Most of 
the traffic carried by the Rock Island could be rerouted over competing rail 
lines . 

The Milwaukee Road serves the northern tier of States from Chicago, Illinois, 
to Seattle, Washington, and has a connection as far east and south as Louis- 
ville, Kentucky. The Milwaukee Road nearly parallels the larger and financially 
strong Burlington Northern. The Burlington Northern does not serve Louis- 
ville but it does serve Paducah, Kentucky, and has the advantage of a line 
all the way to the Gulf of Mexico at Galveston, Texas. 

The ailing Chicago and Northwestern Railroad extends from Lake Superior 
on the north to Kansas City, Independence and St. Louis, Missouri on the south, 
and from Chicago on the east to Wyoming on the west. It is in the process 
of extending a line to coal fields in eastern Wyoming. 

The Illinois Central Gulf Railroad, also an ailing line, connects Chicago, 
in several almost straight lines, with the Gulf of Mexico at New Orleans, | 
Louisiana; Gulfport, Mississippi and Mobile, Alabama. In the south it extends 
from Shreveport , Louisiana on the west to Birmingham and Montgomery, Alabama 
on the east. In the north it extends west to Sioux Falls, South Dakota; Sioux 
City, Iowa; and Omaha, Nebraska. 

The poor financial health of some railroads in the Midwest and West have 
prompted some calls for creating a quasi-government railroad in the Midwest 
and West similar to Conrail in the Northeast and Midwest. Several days of 
public meetings sponsored by the Secretary of Transportation in January and 
February of 1978 were designed to help focus the attention of the public, and 



63 

more especially the railroads in the Midwest and West, upon a program to re- 
structure the railroad network in that part of the Nation. The 4R Act grants 
the Secretary of Transportation authority to facilitate railroad mergers and 
requires the ICC to render a final decision in rail merger cases within 31 
months from the date a merger petition is filed with it. 

It is too early to tell what will be the shape of the resolution to the 
problem of bankrupt railroads in the Midwest and West, but a recent report 
(reference 9) by the Federal Energy Administration (now part of the Depart- 
ment of Energy), one by the General Accounting Office (reference 11) and 
one by the Department of Transportation (reference 8), are valuable aids 
in determining what the major issues are with respect to the ability of U.S. 
railroads to carry the present and future coal production of the country. 
The principal findings of the FEA report are that: (1) All the railroads plan 
to acquire the equipment that will be needed to carry the increased coal 
traffic. (2) Most railroads have already installed heavy duty welded rails. 
(3) Capital acquisition needed for expanding track and rolling stock is not 
viewed by the railroads as a problem. (4) Suddep increases in rail coal traf- 
fic, as contrasted with a steady growth in traffic, could result in backlogs 
and delays in obtaining needed rail and rolling stock due to probable resultant 
shortages of steel plate, castings and forgings , and some c.omponent parts such 
as wheels. (5) Most of the eastern railroads are concerned that the high sulfur 
coal that many of them now carry ultimately may become uneconomical for fuel 
use due to clean air standards. It would facilitate capital investment plan- 
ning by both the railroads carrying eastern coal and the railroads carrying 



1 



64 

western coal if the Federal Government would establish and maintain a steady, 
long-term policy toward air pollution (see 3.4.1). (6) The railroads would 
like the Federal Government to a make strong public commitment to use domes- 
tic coal. (Since the FEA report was released, the Carter Administration has 
proposed such a commitment.) (7) The railroads state that the development of 
coal slurry pipelines would be a serious setback to railroad expansion and 
financing plans (see 3.4.6). (8) The ICC now permits only annual aggregate 
volume rate agreements between railroads and customers. The railroads believe 
that longer term rate agreements, perhaps five years or longer, would facili- 
tate the expansion of rail facilities (see 3.4.4). 

The FEA report states that, "in short, the solvent railroads can handle 
future traffic without significant U.S. Government help," and the GAO report 
agrees with the FEA report . 

A Department of Transportation (DOT) report (reference 8) released Feb- 
ruary 3, 1978, estimates that an investment of $10 billion will be required 
to handle the increased demand for coal transportation by rail. Between 
$5 and $7 billion will be needed to repair and buy new rail cars and approx- 
imately $4-5 billion will be needed to upgrade and build new track. In many 
instances the rail capacity already exists and the new traffic will permit more 
efficient use of investments that are already in place. The report also 
states that rail equipment financing can be handled efficiently and relatively 
inexpensively by the use of equipment trust certificates and by leasing 
equipment from financial intermediaries. 



I 



65 

The DOT report concludes that railroads are handling current coal pro- 
duction without any significant problems and probably will be able to do 
so without great difficulty through 1985 and beyond. The report states 
that lead times for rail investment decisions are usually shorter than for 
coal mines using facilities, thus facilitating the capability of railroads 
to prepare to handle future increases in coal production. 

The DOT report made several recommendations: (1) The DOT should con- 
sider establishing a coal roads and highway program to assure that near-term 
highway transportation problems will not seriously hamper coal production. 
(2) The DOT should develop a program to identify and alleviate adverse com- 
munity impacts of expanded rail transportation of coal. (3) The DOT should 
examine the current rail tariff structure and the question of long-term coal 
transportation rate contracts. (4) The DOT should use its railroad capital 
assistance programs to ensure that necessary investments are made in timely 
fashion by coal handling railroads. (5) An interagency framework should be 
established for examining the secondary transportation effects of coal pro- 
duction. (6) The DOT should establish a continuing program for monitoring 
the Nation's coal transportation requirements. 

The BOT report states that, although many of the railroads in the Midwest 
and West that will have the major growth in coal traffic are financially 
strong and can attract sufficient investment capital for handling the coal 
traffic, there are some uncertainties that could deter them from doing so. 
The uncertainties are: (1) doubts about future coal production as a result 
of environmental problems and user resistance; (2) the possibility that 



24-786 O - 78 - 6 



66 

coal traffic will be carried by pipelines; and (3) possible community oppo- 
sition to large increases in coal unit train traffic. 

The DOT report states that some financially weak midwestern railroads 
might be unable to attract private investment capital and might require 
Federal assistance such as that available under Title V of the 4R Act. 

3.1.7.4 Conrail . The FEA report was much more guarded with respect 
to Conrail. The report concluded that: (1) by 1985, Conrail will need 
at least 10,000 new coal hopper cars; (2) massive upgrading of existing 
track and rolling stock is needed; (3) although several billion dollars 
have been made available to Conrail for purchasing new rolling stock and 
for upgrading existing track and rolling stock, it is not known exactly 
how much of these funds will be used to upgrade coal-hauling track and 
equipment; (4) close FEA attention is needed to assure that adequate coal- 
hauling rolling stock is purchased and that sufficient upgrading of coal- 
hauling track and equipment is accomplished. Conrail officials have said 
that some of its coal lines are not on high-traffic-density lines and 
will have to compete with other priorities for available funds. 

This concern of the FEA is underscored in several recent reports, by 
the ICC, United States Railway Association (USRA) that oversees Conrail 's 
financial situation, and by Conrail, stating that, among other problems, 
track and equipment were in worse condition than earlier reported and that 
rail traffic projections were higher than the actual traffic that has 
been available for rail transportation. These factors, coupled with storm 



67 

damage to facilities, unusually cold weather the last two winters (1976-1977 
and 1977-1978), and the longest coal strike in U.S. history in 1977-78, will 
delay the date when Conrail can be expected to earn a profit. Furthermore, 
it means that the Federal Government will be called upon to provide Conrail 
with additional financial aid, and that Conrail might have greater pressure 
on it for use of funds on projects other than to improve its ability to 
carry more coal. Specific details would be desirable, but are largely unavailable 
to the public at large at the present time. 

3.1.7.5 Other Studies Relating to Coal Movement . The September 22, 
1977, GAO report (reference 11) and the FEA report (reference 9) agree that 
without oversight of Conrail investment decisions, Conrail might not invest 
in sufficient coal-traffic related purchases and upgrading to handle forecasted 
coal traffic. These two reports and the DOT report (reference 8) are in 
agreement as to the ability of solvent railroads to handle the additional 
coal traffic. 

A number of other studies are available on the subject of the 
ability of railroads to handle future coal production. A 1974 study 
by Peat, Marwick, Mitchell & Co. (reference 5) provides even more de- 
tail than the GAO report on projected rail freight car requirements to 
handle increased coal traffic and, in general, is in agreement with the 
FEA, GAO and DOT studies. The Manalytics study (reference 3) points out 
specific potential bottlenecks in the rail and barge coal-handling net- 
work which should receive the attention of Congress with respect to con- 
struction programs on the domestic waterway system. These bottlenecks 
are discussed at greater length in 3.4.2 as they relate to Western coal. 



68 

The Richard J. Barber Associates, Inc. study (reference 6) provides 
support for the railroad industry's position that it can handle the pro- 
jected increased rail coal traffic and that coal slurry pipelines are therefore 
unnecessary. The Center for Advanced Computation study (references 2 and 
3) provides information on the relative cost efficiency of various modes 
of transporting coal. Information of the type contained in references 
2 and 3 could be helpful in the establishment of a congressional policy toward 
the construction of total coal transportation facilities, such as coal 
slurry pipelines and the possible impact of such facilities on the existing 
rail, truck and barge network. 

3.1.7.6 Mergers, Abandonments and Intermodal Transportation; Their 
Effect on Energy Transportation. Railroad mergers have been going on from 
the beginning of railroading in the United States and have received considerable 
interest as a tool for improving the economic health of the industry. The 
Transportation Act of 1920 required the Interstate Commerce Commission to 
establish a plan for rail mergers and to encourage the railroads to merge 
according to the plan. This policy was considered a failure and abandoned 
during the depression of the 1930' s. In 1976, a different approach to rail 
mergers was embodied in the law. The Railroad Revitalization and Regulatory 
Reform Act of 1976 (usually referred to as the 4R Act) granted the Sec- 
retary of Transportation immunity from the antitrust laws in convening meet- 
ings of railroad representatives to discuss rail mergers. The law also 
provided funds for the Secretary to use in the encouragement of mergers 
which he approved. The Act also encouraged mergers by requiring the ICC 
to complete and issue a final decision in all rail merger petitions within 



69 

31 months from the date the original proposal is submitted to it. In fur- 
therance of its responsibilities in rail merger cases, the ICC required its 
Rail Services Planning Office (RSPO) to conduct a study of the various as- 
pects of rail mergers. 

The final report by RSPO was issued on February 1, 1978, and recom- 
mended that the ICC issue a policy statement: (1) encouraging rail re- 
structuring through the merger process and spelling out policies which 
the Commission intends to follow in deciding merger proceedings; (2) recog- 
nizing that end-to-end mergers generally provide potential for greater 
long-term advantages with fewer risks than parallel mergers; (3) empha- 
sizing that voluntary agreement among carriers rather than governmental 
directive is the preferred method of rail restructuring: (4) acknowledging 
that the labor protective conditions which it will impose in merger pro- 
ceedings will be those identified by statute and encouraging the volun- 
tary negotiation of implementing agreements prior to a final decision 
on the merger; (5) declaring that mergers are not a proper or effec- 
tive method for dealing with marginal carriers, and that the Commis- 
sion's primary responsibility is to assure adequate service rather 
than to preserve corporate entities; (6) continuing its present poli- 
cies with respect to national defense as a merger criterion; however, 
a formal channel should be established with the Department of Defense 
to provide notice of merger filings at the earliest possible date; 
(7) continuing its present procedures on environmental impact and es- 
tablishing formal channels with appropriate agencies on community im- 
pact. In addition, RSPO recommends that: (1) the ICC and DOT take 



70 

several specified steps to clarify and simplify the merger process; 
(2) the ICC should continue its dialogue with Congress, the trans- 
portation community, States and other governmental agencies with a 
view toward identifying and resolving railroad problems. 

The RSPO report concluded that end-to-end mergers provide many 
opportunities for improving operating efficiencies and entail fewer 
problems of coordinating the management and labor force of the merged 
lines than do parallel mergers. Parallel mergers appear to offer greater 
opportunities to improve the density of traffic on lines, abandon du- 
plicated facilities, and reduce the management and labor forces. But 
as the merger of the Pennsylvania Railroad and New York Central Rail- 
road demonstrated, these objectives are difficult to achieve. Rail 
mergers usually take years to be approved and years to achieve improved 
operating efficiencies after the merger occurs. Thus, dramatic im- 
provement in the railroads' ability to handle coal as a result of mer- 
gers would likely have much more impact in the post 1985 period than 
in the period between now and 1985. The RSPO report concluded that 
substitutes to mergers, such as run-through trains, would not be as 
effective as mergers in improving the operating efficiencies of rail- 
roads . 

Abandonment of rail lines has been going on gradually for decades 
and may accelerate as a result of the 4R Act that provides short-term 
Federal financing for rail lines which the railroads obtain approval from 
the ICC to abandon. The criteria the ICC must use in deciding abandon- 
ment cases are, under the 4R Act, different from those under prior legis- 
lation, and the change appears to make abandonments easier. Not enough 



71 

experience under the 4R Act has been accumulated, however, upon which 
to make a conclusive finding. What does seem clear is that many branch 
lines lose money and that abandonment of these lines will somewhat im- 
prove the financial health of railroads. 

The Interstate Commerce Act gives the ICC authority to require in- 
termodal connections between railroads and trucks and between railroads 
and barges. Thus, possible resistance on the part of one carrier to make 
intermodal connections with a carrier of another mode is not likely to 
present a problem for policymakers. 

3.1.7.7. General Energy Policy Problems . The conclusions that can be 
drawn from the discussion above are that, while there may be some geographical 
bottlenecks to the use of the most direct rail routes, and some possible 
delays in acquiring sufficient rolling stock, in general the solvent railroads 
will be able to obtain sufficient financing to obtain rolling stock and 
to upgrade roadbed; and suppliers will be able to produce rails, locomotives 
and coal hopper cars fast enough to meet a steady growth in coal traffic 
at the rate predicted by the General Accounting Office, and possibly, at 
the rate targeted in the Carter Administration's National Energy Plan . 

While Conrail has received, and is expected to continue receiving, 
a substantial amount of Federal assistance, Conrail may not choose freely 
to invest sufficiently in track and rolling stock to handle future coal 
production. It may not consider such investment as contributing suffi- 
ciently to its efforts to minimize losses and eventually become profitable. 

2/ See the Manalytics study for details on which routes, and for conclusions 
somewhat more pessimistic than the other reports about the ability of the 
rail and water networks to handle the projected increased coal traffic. An 
updated version of the Manalytics report is expected to be released in the 
near future. 



72 



In order to assure that ample investment is made in coal lines and rol- 
ling stock, Congress may have to make such priorities a matter of public 
record and establish a mechanism for implementing them. Perhaps this 
mechanism would require legislation granting the USRA or the ICC authority 
to require Conrail to make these investments, and to evaluate Conrail's 
compliance with such standards. Also, Congress might wish to require the 
ICC to allow railroads to establish aggregate rate contracts with customers 
for terms exceeding one year. 

References 



1. Briggs, Richard E. The case against coal slurry pipelines," Trans- 

port 2000, July /August, 1977, pp. 20-22. 

The future rail haul of coal," Transport 2000, May/June, 1977, 

pp. 22-23. 

2. Center for Advanced Computation, University of Illinois. Comparative 

coal transportation costs: an economic and engineering analy- 
sis of truck, belt, rail, barge, and coal slurry and pneumatic 
pipelines. Prepared for the U.S. Department of the Interior, 
Bureau of Mines and the U.S. Federal Energy Administration. 
Urbana, Illinois, August, 1977. 8 vols. 

3. Manalytics, Inc. Coal transportation capability of the existing rail 

and barge network, 1985 and beyond. Prepared for the Electric 
Power Research Institute. San Francisco, September, 1976. 72 
pages plus appendices. 

4. O'Hara, Edward, Moving coal. Transportation, USA, Fall, 1977. Washing- 

ton, U.S. Department of Transportation, published quarterly, pp. 
2-5. This is a brief article that gives the reader a broad over- 
view of coal transportation (emphasizing rail) and referring to the 
Coal Transportation Task Force established by Secretary of Trans- 
portation Adams. The Task Force's report is reference 8. 

5. Peat, Marwick, Mitchell & Co. Railroad freight car requirements for trans- 

porting energy, 1974-1985. Prepared for U.S. Federal Energy Admini- 
stration, U.S. Department of Commerce, and U.S. Department of Trans- 
portation. Washington, November, 1974. Various pagings. 



73 



6. Richard J. Barber Associates, Inc, The railroads, coal and the National 
Energy Plan: an assessment of the issues. Prepared for the fol- 
lowing railroads: Burlington Northern, Chicago and North Western, 
Kansas City Southern, Missouri Pacific, Santa Fe, and Union Paci- 
fic. Washington, September, 1977. 80 pages plus appendices. 

7. Schrier, Elliot. Rail haul of coal, transport 2000, July/August, 1977, 
pp. 6-7. This is a reply to Richard Briggs ' article cited above 
entitled "The Future Rail Haul of Coal." Mr. Briggs' article cri- 
tiqued the Manalytics, Inc. study cited above. 

J. U.S. Department of Transportation. Coal Transportation Task Force. 

Transporting the Nation's coal - a preliminary assessment. Wash- 
ington, January, 1978. Various pagings. 



U 



,S. Federal Energy Administration. Office of Coal. Coal rail trans- 
portation outlook. Washington, May, 1976. Various pagings. 



10. U.S. General Accounting Office. An evaluation of the National Energy 
Plan. Washington, July 25, 1977. Report number EMD-77-48. Vari- 
ous pagings. 

11. U.S. coal development - promises, uncertainties. Washington, 

September 22, 1977. Report number EMD-77-43. Various pagings. 

12. U.S. Interstate Commerce Commission. Rail Services Planning Office. 
Rail merger study. 7 vols, plus a final report. Washington, 1977 
and 1978. Various pagings. 



13. U.S. Library of Congress. Federal aid to domestic transportation. 
Washington, May 1977. 169 p. 



74 



3.1.8. Effects of Hazardous Materials Transportation Regulations on the 
Delivery of Energy Products */ 

3.1.8.1. Issue Definition . The hazardous materials transportation 
regulations, issued by the Department of Transportation (DOT), are 
designed to promote the safe shipment handling, and containerization 
of hazardous materials in commerce. Energy products are generally 
classified as being hazardous materials. Accordingly, transporters 

of energy products are compelled by law to obey DOT regulations. 

Several industry and government officials interviewed for this study 
maintained that DOT regulations have not been a major impediment to the 
delivery of energy products. However, these spokesmen expressed concern 
over two major areas: overlapping and conflicting Federal and State reg- 
ulations, and limited enforcement of DOT regulations. As the Congress 
continues its oversight responsibility over the transportation of hazardous 
materials, increased attention might be directed at these concerns.. 

3.1.8.2. Introduction . Substances such as liquefied petroleum 
gas, gasoline, naptha, nuclear materials, and fuel oil are transported 
in large quantities to supply this Nation with its energy needs. Under 
the Hazardous Materials Transportation Act, P.L. 93-633, these energy 
products are classified as hazardous materials since they may "pose 

an unreasonable risk to health and safety or property when transported 
in commerce." When improperly handled or transported, these materials 
can cause violent explosions, result in tremendous fires, and otherwise 
endanger human life and property. 

*/ Prepared by Paul Rothberg, Analyst, Science Policy Research Division. 



75 

Federal and State governments have issued regulations to protect 
the public from unsafe transport, storage, and handling of these materials. 
These regulations directly influence the containerization , transporting, 
and administrative operations of railroad carriers, petroleum companies, 
ship owners, and other persons involved in the transport of hazardous 
materials. For example, these regulations may specify the type of 
container that is allowable for transporting hazardous materials, 
the requirements for identification signs on transporting vehicles, 
the marking of containers, and administrative procedures, such as 
shipping papers. In addition, these regulations specify procedures 
for reporting an accident involving the transportation of a hazardous 
material. An array of special regulations pertain to the shipment 
of hazardous materials by rail, public highway, waterway, and air.. 

As part of this study, several industry spokesmen were interviewed 

to survey their views on the effect of hazardous materials transportation 

1/ 

regulations on the delivery of energy products. Their specific 
concerns and possible solutions offered by these spokesmen are presented 
in this chapter. 

3.1.8.3. Laws and Regulations . The DOT has primary responsibility 
for regulatory activities concerning the transportation of hazardous 
materials. DOT's principal authority for issuing hazardous materials 

_1/ Individuals interviewed include: William Miller, C.T. Sawyer, and 

Ronald Jones of the American Petroleum Institute; Clifford Harvison of 
the National Tank Truck Carriers, Inc.; William Jennings, a private 
consultant; Richard Stock of the National LP-Gas Association; and 
several other industry representatives. 



76 

transportation regulations and enforcing Federal standards includes: 

the Federal Aviation Act of 1958, the Dangerous Cargo Act of 1940, 

the Tank Vessel Act of 1936, the Ports and Waterways Safety Act, the 

Hazardous Materials Transportation Act, the Federal Railroad Safety 

Act of 1970, the Federal Water Pollution Control Act (as amended), 

and the Transportation of Explosives Act. Under these Acts, the Department 

regulates classification, marking and labeling, placarding, packaging, 

shipping papers, compatibility of stowage, and handling of hazardous 

materials. Also, the Department has authority for research related 

to the transportation of hazardous materials, collection and compilation 

of data on certain accidents involving materials in transport, cooperation 

with the Attorney General for enforcement of laws violated during 

the transport of hazardous materials, international and interagency 

coordination, and accident investigations. 

With the passage of the Hazardous Materials Transportation Act 
in 1975, Congress sought to improve the regulatory and enforcement 
authority of the Secretary of Transportation in dealing with hazardous 
materials. This Act seeks to protect the Nation against the risk to 
life and property inherent in the transportation of these substances 
in commerce. Under this Act, the Secretary of Transportation is authorized 
to establish criteria for handling hazardous materials. Such criteria 
may include, but need not be limited to: type and frequency of inspection; 
a minimum number and level of training and qualification for personnel 
handling hazardous materials; equipment to be used for detection, 
warning, and control of risks posed by such materials; specifications 



77 

regarding equipment and facilities used in the handling of such materials; 
and a system of monitoring safety assurance procedures for the transportation 
of such materials. Also, this law authorizes the Secretary of Transportation 
to issue regulations for the safe transportation of hazardous materials. 
These regulations may govern any safety aspect which the Secretary 
deems necessary or appropriate. 

Certain provisions of the Hazardous Materials Transportation 
Act seek to accomplish: 

— The removal of statutory restrictions on the Secretary's authority 
to centralize DOT regulatory activities relating to the safe transportation 
of hazardous materials by various modes; 

— The extension of the Secretary's authority to impose civil penalties 
for the illegal transportation of hazardous materials by various modes; 

— A significant increase in the criminal sanctions for violations of 
hazardous materials regulations; 

— Provisions of various forms of specific relief (court action) 
as additional enforcement tools; 

— A broadening of the definition "commerce" to include transportation 
which affects interstate transportation; 

— A broadening of the application of hazardous materials regulations 
in certain geographical locations; 

— Federal preemption of inconsistent State and local regulations 
pertaining to the transportation of hazardous materials; 

— Authorization for the Secretary to require shippers and carriers 

of hazardous materials, and manufacturers of hazardous materials containers, 
to register with the Department of Transportation. 



78 

Since the passage of this Act, Congress has continued its oversight 
of Federal laws and regulations concerning the transportation of hazardous 
materials. For example, the Subcommittee on Surface Transportation of the 
Senate Conmierce Committee held hearings in 1976 to evaluate the effectiveness 
of the DOT and the Ford Administration in implementing the Act. During 
these hearings, DOT spokesmen stated that progress had been made in 
implementing only some of the provisions of the Act. However, it was 
announced that the Department was undertaking a major consolidation and 
simplification of existing Federal regulations governing the transportation 
of hazardous materials. Over the long run, this consolidation may 
improve the Department's capabilities to carry out its responsibilities 
and may aid shippers and carriers in understanding and complying with 
Federal regulations. 

In addition to regulations promulgated by the Department of Transporta- 
tion, the Occupational Safety and Health Administration, United States 
Geological Survey, Army Corps of Engineers, and the Environmental Protection 
Agency issue regulations and implement policies that bear on the transporta- 
tion of hazardous materials, lae Department of Energy and the Nuclear 
Regulatory Commission have important responsibilities in the transportation 
of radioactive materials. This subject area is discussed in chapters 3.1.5. 
and 3.1.6. of this study. There are also numerous State agencies that deal i^th 
pipeline safety and transportation of hazardous energy products. 

^•^•S''^- Areas of Concern . Industry spokesmen have indicated 
that the regulatory system governing the transportation of hazardous 
energy products is generally working satisfactorily. Large quantities 



79 

satisfactorily. Large quantities of energy products such as liquefied 
petroleum gas, gasoline, fuel oil, and naptha are transported daily 
with few incidents. The number of deaths each year from transportation 
accidents involving all hazardous materials is relatively low — usually 
about 30 — in comparison to the potential number of deaths that might 
occur from a major catastrophe. 

Industrial groups generally favor many Federal regulations that 
promote the safe transport of hazardous materials. These regulations help 
reduce potential dangers to their employees, and protect their investments 
in equipment and materials. Industry spokesmen stated that they find 
the Federal regulatory system "basically sound," "working pretty well," 
and that they try to develop "a harmonious relationship with government." 

The industry statements presented above seem compatible with an 
opinion expressed by the Acting Chief of the Office of Hazardous Materials 
Operations of the DOT, who stated that it appears that DOT hazardous 

materials regulations have generally not limited the transportation of 

2/ 

hazardous energy products to market. 

Although there appears to be a consensus that the regulatory system 
is working satisfactorily, several industry representatives have expressed 
concern over three areas: (1) overlapping and conflicting regulations, 
(2) lax enforcement of existing Federal regulations, and (3) costs 
of regulations. 

A. Overlapping and Conflicting Regulations 

Several Federal agencies and many State governments issue regulations 
that affect the transportation of hazardous materials. According to some 

11 Telephone communication with Paul Sea, DOT, 1977. 



80 

industry spokesmen, this sometimes results in conflicting, duplicative, im- 
practical, and unnecessary regulations. Presented below are several 
examples of testimony and interview data that illustrate these concerns. 

Mr. Clifford Harvison, Managing Director of the National Tank Truck 
Carriers, Inc., recently criticized in congressional testimony the limited 
expertise of many Federal officials who regulate the transportation of 
hazardous materials. Although Mr. Harvison had high praise for the high 
quality of professionalism that has developed within the cadre of hazardous 
materials regulators at the Department of Transportation, he argued that 
regulations issued by some Federal agencies, such as the Occupational 
Safety and Health Administration and the Environmental Protection Agency, 
"are so wholly impractical in their application to transportation as to 
literally prohibit compliance." 

Mr. Harvison also stated that there was duplication of effort in the 
Federal regulatory system. He argued ".... I'm convinced that only clear 
congressional mandate can prevent the wasteful duplication of effort and 
the 'left hand not knowing what the right hamd is doing' syndrome that 
produces poor, disjointed regulation — regulation which neither serves 
nor protects anyone." For example, Mr. Harvison indicated that regul- 
ations issued by the Occupational Safety and Health Administration pertain- 
ing to vinyl chloride conflicted with regulations issued by the Department 
of Transportation. As a result, he stated: 

"il U.S. Congress. Senate. Committee on Commerce, Subcommitte on 
Surface Transportation. Hazardous Materials Transportation Act. 
March 4, 1976. Serial No. 94-93, p. 37. 

4/ Ibid. , p. 38. 



81 

"We have two sets of shipping paper requirements as well as dif- 

5/ 

fering sets of loading, unloading, labeling, and placarding equipments. 

Mr. Ronald Jones of the American Petroleum Institute maintained 
that the vast array of complex and sometimes conflicting regulations is- 
sued by Federal and State agencies has resulted in special problems for 
the petroleum industry. For example, he indicated it is difficult for 
this industry to operate a single type of gasoline truck that could 
travel throughout the United Sates because State regulations for safety 
and pollution devices used on these vehicles vary. 

In addition, Mr. Jones maintained it is difficult for transporters of 
petroleum to keep current with all hazardous materials transportation reg- 
ulations. (These regulations require over 1,000 pages of print in 
the Code of Federal Regulations.) He argued that State laws and regulations 
simply add another "layer on top of Federal requirements." Some State 
laws, according to this spokesman, were restricting delivery of energy 
products to market. He cited a recently-passed Washington law that 
limited the size of tankers which could enter the waters of that State. 
Thus, under this law, it appears that only "smaller" tankers carrying 
"smaller" loads of energy products will be allowed to enter Puget 
Sound in Washington. 

Mr. Jones summarized that the combination of problems resulting from 
(1) too many Federal agencies involved in writing regulations, and (2) 

5_/ Ibid. 



24-786 O - 78 - 7 



82 

overlapping and conflicting Federal and State regulations, resulted in an 

6/ 

impediment to the efficient transportation of energy products. 

B. Lax Enforcement of Some Federal Hazardous Materials Transportation 
Regulations . 

An industry spokesman interviewed for this study maintained that the 
Federal Government does not rigorously enforce all of the hazardous 
materials transportation regulations. Mr. Clifford Harvison stated that 
many independently owned tank truck operators who transport hazardous 
materials do not meet current Federal standards. Specifically, these 
vehicles do not meet DOT placarding standards that require clearly 
marked warning signs on vehicles transporting flammable liquids. He 
writes: 

There are, however, thousands of trucks, operated daily laden 
with (primarily) petroleum products which have (literally) no 
restrictions. They are independently owned, rarely have a sign on 
the door, and are driven under the aegis of brokers or commission 
agents. Technically, they are under DOT jurisdiction, however, the 
total lack of identification on the trucks makes safety enforce- 
ment a laughing matter. They don't acknowledge DOT regulations; 
their drivers know no hours of service regulations; they don't 
even report accidents. Ij 

These "illegal" shipments are apparently undertaken even though 
strict penalties may be imposed on violators. As stated in Section 
110 (a) of the Hazardous Materials Transportation Act, "Whoever knowingly 
commits an act which is in violation of any regulation, applicable to 



6^/ Personal communication with Ronald Jones, American Petroleum 
Institute, 1977. 

IJ Personal communication with Clifford Harvison, Natural Tank Truck 
Carriers, Inc., 1977. 



83 

any person who transports or causes to be transported or shipped hazardous 
materials, shall be subject to a civil penalty of not more than $10,000 
for each violation, and if any such violation is a continuing one, each 
day of violation constitutes a separate offense." Section 110 (b) of 
this same law provides for criminal penalties — "A person is guilty of 
an offense if he willfully violated a provision of this title or a reg- 
ulation issued under this title. Upon conviction, such person shall be 
subject, for each offense, to a fine of not more than $25,000, imprison- 
ment for a term not to exceed 5 years, or both." 

Inspection, compliance, and enforcment of DOT hazardous materials 
transportation regulations are delegated to decentralized administrations, 
within DOT, such as the Federal Railroad Administration and the Federal 
Highway Administration. The following table (Table l)indicates the number 
of hazardous materials regulations violations noted by the Department 
in 1974 and 1975 and the number of enforcement actions taken. The 
Department has made an effort to increase its inspection activities 
and it has noted a "marked improvement in compliance with the hazardous 
materials regulations." 8^/ 



8^/ U.S. Congress, Senate. Hazardous Materials Transportation Act. 
op. cit . , p. 6 and 13. 



84 



TABLE I 

HAZARDOUS MATERIALS REGULATIONS VIOLATIONS AND ENFORCEMENT ACTIONS */ 



Operating administration 
— Activity/ action 


1974 


1975 


Change 


Percen 
chang 


USGS : 










Port facilities: 










Total violations detected 


2,871 


1,932 


-939 


-33 


Corrected on spot 


1,605 


668 


-937 


-58 


Advisory warnings issued 


1,266 


1 ,264 


- 2 





Vessels: 










Civil penalties initiated 


1,155 


866 


-289 


-25 


Civil penalties collected 


1 ,080 


AAA 

900 


1 O A 

-180 


1 T 

-17 


Total collected 


$139,990 


$84,500 


-$55,490 


-40 


Average penalties 


$130 


$94 


-$36 


-28 


FAA: 










Total enforcement actions 


244 


192 


-52 


-21 


Administrative action 


106 


88 


-18 


-17 


Civil penalties 


1 o o 
1 JO 




-34 


-25 


Total assessed 


$178,150 


$202,900 


-$24,750 


+14 


Average penalty assessed 


1,291 


1,951 


+ 660 


+51 


Total collected 


$104,400 


$ 78,150 


-$26,250 


-25 


FHWA (BMCS): 










Total enforcement actions 


269 


205 


-64 


-24 


Criminal case initiated 


79 


159 


+80 


+ 101 


Criminal cases closed 


103 


64 


-39 


-38 


Fines adjudged 


$ 67,200 


$ 24,865 


-$42,335 


-63 


Average fine 


$652 


$ 389 


$263 


-40 


FRA: 










Administrative corrective action cases 


1,200 


2,100 


+900 


+ 75 


Criminal counts initiated 


19 


36 


+ 17 


+89 


Criminal counts closed 


32 


17 


- 15 


-47 


Fines adjudged 


$ 15,850 


$7,100 


-$8,750 


-55 


Average fine/count 


$ 495 


$ 418 


-$ 77 


-16 


Civil claims (1) 





7 






Total collected 





$11 ,000 






Average penalty/claim 




$1,570 







(1) Under Federal Railroad Act of 1970 for violations of FRA Emergency Order No. 5 
prohibiting the free rolling switching of certain tank cars filed with high 
pressure compressed gas. 

*J Source: Department of Transportation 



85 

C . Costs of Regulations 

Some industry officials have complained about the economic burden 
imposed by DOT regulations. For example, a spokesman for the National LP-Gas 
Association maintained that compliance with DOT hazardous materials 
transportation regulations imposed large costs on many of the small 
operators in this industry. Following detailed administrative procedures 
and reporting requirements can be difficult and costly for these opera- 
tors. This spokesman questioned the cost/benefit ratio (of these 
regulations) 9^/ 

3.1.8.5. Policy Alternatives . Several industry groups have raised 
questions concerning the effectiveness and efficiency of hazardous 
materials transportation regulations. As technology advances and as 
market and transportation conditions change, this regulatory system 
is frequently updated. As this occurs, it would seem appropriate to 
consider congressional and administrative options to improve the trans- 
portation of hazardous materials. These include: 

A. Regulatory Reform and Revision; 

B. Improved Enforcement of Hazardous Materials Transportation 
Regulations; and 

C. Eliminating Federal Regulations and Converting to an Economic 
Penalty System. 



9^/ Personal communication with Richard Stock, National LP-Gas Association, 
1977. LP stands for liquefied petroleum. 



86 

A. Regulatory Reform and Revision 

1. Status Quo Option. According to several of the industry 
spokesmen interviewed, the Federal regulatory process governing the 
transportation of hazardous materials appears to be working satisfactorily. 
One option, therefore, would be to continue periodically to revise 

and update hazardous materials transportations regulations. As safety 
technologies are improved, and as transportation needs and technologies 
change, the Department of Transportation could continue its practice 
of trying to improve its regulations. 

2 . Suggestions Offered by the American Petroleum Institute 

Ronald Jones of the American Petroleum Institute suggested that there 
is a need for national uniformity of regulations impacting on the transporta- 
tion of hazardous materials. He maintained that there ought to be a 

lead agency in this area. Federal regulatory action should be centered 

10/ 

in a single location. Each functional modal administrator, according 
to Mr. Jones, should be given primary responsibility for matters concerning 
the transportation of hazardous materials. For example, he argued that 
the U.S. Coast Guard ought to be given primary responsibility in water 
shipping matters. 

Mr. Jones was in favor of trying to "optimize" regulations concerning 
the transportation of hazardous materials. He sought to "cut out the minor 

11/ 

impediments and unnecessary expenses that come with the regulatory process. 

10/ Personal communication with Ronald Jones, American Petroleum 
Institute, 1977. 

11 / The DOT has responsibilities in the different transportation modes, 
such as rail, air, and water. The Department has divided itself into 
separate organizations, such as the Federal Railroad Authority, 
the Federal Aviation Authority, and the U.S. Coast Guard, to 
handle its responsibilities in the different transportation modes. 



87 

It appeared that Mr. Jones would be in favor of strengthening 
the use of preemption authority of the Secretary of the Transportation 
as provided for in the Hazardous Materials Transportation Act which specifies 
that: 

Sec. 112. (a) General. — Except as provided in subsection (b) of 
this section any requirement, of a State or political subdivision 
thereof, which is inconsistent with any requirement set forth in 
this title, or in a regulation issued under this title, is pre- 
empt ed . 

This action could possibly reduce conflicts between Federal and State 
regulations governing the transportation of hazardous materials. 

According to Mr. Jones, there are good reasons to continue revising 

the existing regulatory system. He stated that "in the best of all 

worlds" i.e., no duplication of regulations and coordination throughout 

the Federal and State systems, there would be a reduction in the costs 

of transportation, there would be an increase in efficiency, and there 

12/ 

would be a general facilitation of traffic. 

B . Improved Enforcement of Hazardous Materials Transportation Regulations 
According to statements made by Mr. Harvison, there appears to be 
lax enforcement of some hazardous materials transportation regulations. It 
seems reasonable that some Federal department, e.g.. Department of Justice 
or Department of Transportation, or the appropriate congressional committees 
might review and investigate this allegation. The level of compliance 
of all hazardous materials transportation regulations might also be 
examined. Important questions that seem to warrant attention include: 



111 Ibid. 



88 



— How widespread are violations of the hazardous materials transporta- 
tion regulations? 

— Do the manpower resources of the Department of Justice and/or 
Department of Transportation need to be increased in order 
that enforcement activities might be strengthened? 

— Do criminal or civil penalties for violating hazardous materials 
transportation regulations need to be increased? 

C . Eliminating Federal Regulations and Converting to an Economic Penalty 
Syst em 

An alternative to the existing complex regulatory system might be to 
eliminate Federal regulations, statutes, and codes affecting the transportation 
of hazardous materials, and replace these with a system of severe economic 
penalties to be imposed on any industry found to be at fault in an 
accident involving the transportation and/or release of hazardous 
materials. For example, if a petroleum company were transporting 
fuel oil to its customers and caused an accident which resulted in 
the release of a hazardous material, a severe financial penalty would be 
imposed on that company. 

A possible advantage of this scheme might be to reduce the regulatory 
burden on industry. Procedures and control technology considered unnecessary 
by industry could be eliminated. The efficiency of delivering hazardous 
materials might increase, if the delivery cost could be reduced. 

However, there are several major disadvantages with this alternative. 
An economic penalty system might not adequately protect the public from the 
dangers inherrent in the transportation of hazardous materials. Some 
companies might simply go into bankruptcy if they were involved in an 
accident and forced to pay substantial penalties. Other companies might 
simply refuse to carry hazardous materials if the economic risks were too great. 



89 

For some accidents, it might be difficult to identify the party at fault. 
It would also be difficult to determine the amount of economic compensation 
when loss of life is involved. Another problem with this alternative 
would be the existence of State and possibly local regulations that 
affect the transportation of hazardous materials. Eliminating Federal 
regulations would not eliminate State and local regulations. 

3.8.8,6. Cone lusion . Most energy products are hazardous materials. 
If improperly handled, these substances can pose a risk to health, safety, 
and property. To protect human life and to promote transportation safety, 
the Congress has passed several laws, and Federal agencies have implemented 
a complex set of regulations that govern the transportation, handling, and 
containerization of hazardous materials. The current Federal regulatory 
system affecting the delivery of energy products appears to be working 
satisfactorily; however, questions have been raised by industry spokesmen 
regarding overlapping and duplicative regulations, their level of enforcement 
by the DOT, and the costs of compliance with them. As the Congress continues 
its long established interest in improving the hazardous materials trans- 
portation regulations, increased attention might be directed at some of 
the concerns cited in this study. 

References 

U.S. Coast Guard. Liquified natural gas, views and practices, policy 
and safety. February 1976. Washington, D.C. 1976. (CG-478) 

U.S. Department of Transportation. Sixth annual report of the Secretary 
of Transportation on hazardous materials control, calendar year 1974. Washingt 
D.C. 1975. 55 p. 



90 



U.S. Department of Transportation. Office of Hazardous Materials. Report 
to the Deputy Secretary of the Task Force on Hazardous Materials in Air 
Commerce. Mar. 19, 1975. Washington, D.C., 1975. 27 p. 

U.S. Congress. Senate. Committee on Commerce, Subcommittee on Surface Trans- 
portation. Hazardous Materials Transportation Act. March 4, 1976. 
Serial No. 94-93, p. 37. 



91 

3.1.9. Waterway User Charges .''^' / 

3.1.9.1. Introduction . The Federal Government pre.sently maintains 
about 25,000 miles of navigable waterways, approximately 15,000 
miles of which are commercially significant. Every Administration 
beginning with Franklin Roosevelt's has recommended the levying 
of waterway user charges, but until the 94th and 95th Congresses, 
the legislative branch has shown little interest in the subject. 

The legislative proposals which have received the most Congres- 
sional consideration during the 95th Congress would levy charges to 
recover a proportion of Federal expenditures on inland waterways, but 
not on the Great Lakes or on deep water channels maintained for use 
by ocean-going vessels. The two most comnionly discussed forms of a 
user charge are (1) fees based on the amount of expenditures by the 
Federal Government on the specific segment of the inland waterway 
system over which the subject traffic is carried, and (2) a uniform 
fuel tax levied on all traffic, designed to recover a portion of all 
Federal expenditures on the entire inland waterway system. 

A significant amount of coal and petroleum is transported over 
the inland waterways. One purpose of this section is to discuss whether 
waterway user charges would impede the flow of coal and petroleum to 
consuming areas of the country. Another purpose is to discuss general 

*/ Prepared by Dr. Stephen J. Thompson, Analyst in Transportation, 
Economics Division, and Louis Alan Talley, Research Analyst 
in Taxation, Economics Division. 



92 

energy transportation issues raised by the possible levying of a water- 
way user charge. 

3.1.9.2. Background . The importance of energy traffic carried 
on the Mississippi River System is illustrated by the information 
in Table 1 and the relative importance of water carriers in the 
transportation of coal and petroleum is illustrated by the information 
in Table 2. 



Table 1. Commodity Composition of Mississippi River 
System Traffic , 1972 



Commodity 


Rank Order of 
Mississippi River 
Traffic 


Ton-Miles 
(Billions) 


Percent of Total 
Mississippi River 
Traffic 


Coal 


1 


32 


17.8 


Crude Oil 


3 


20 


11.0 


Gasoline 


5 


13 


7.4 


Residual Oil 


8 


8 


4.6 


Distillate Fuel 


11 


_5 


2.9 


Total 




78 


43.7 



Source: U.S. Department of Transportation. Modal Traffic Impacts of 
Waterway User Charges . Washington, 1977. Vol. II, p. IX-2. 



93 



Table 2. Modal 


Ranking by Volume of Traffic 


Carried 


Type of Carrier 


Coal 


Petroleum 


Railroads 


1 


5 


Waterway Carriers 


2 


4 


Trucks 


3 


3 


Ocean Carriers 


4 


2 


Pipelines 


5 


1 



Source: U.S. Congress. Senate. Committee on Energy and Natural Re- 
sources and Committee on Commerce, Science, and Transporta- 
tion. National Energy Transportation, Vol. I-Current Systems 
and Movement s . Washington, U.S. Govt. Print. Off., 1977. 
(95th Congress, 1st session. Committee print., publication 
no. 95-15.) p. 3. Prepared by the Congressional Research 
Service. 



3.1.9.3. 20 Percent Differential . The transportation rates 
charged by water common carriers operating on the inland waterways 

1/ 

are typically about 20 percent below rail rates for the same traffic. 

It is widely held that this price margin is necessitated by the 

less flexible service which water carriers provide. But the question 



_1/ See, for example, D. Philip Locklin, Economics of Transportation. 

Homewood , Illinois, Richard D. Irwin, 1972, p. 742. For a discussion 
of rail-water rate competition, see ibid . pp. 494-497 and 528-529; 
and Charles F. Phillips, Jr., The Economics of Regulation, Homewood, 
Illinois, Richard D. Irwin, 1969, pp. 323-324. 

Ij Less flexible service refers to the slowness of water transportation, 
its seasonal characteristics on some waterways, occasional interrup- 
tion of service due to drought and floods, the need to transfer freight 
which does not both originate and terminate on waterways, and, at least 
in some instances, less liability for loss and damage. 



94 

arises whether water carriers could continue to provide service at rates 
20 percent below rates charged by other carriers if water carriers were re- 
quired to reimburse the Federal Government for constructing and operating 
locks and dams and maintaining the waterways in navigable condition. If 
water carriers were to raise their rates significantly, railroads might 
try to attract waterborne traffic by maintaining or even reducing their 
current rates. (Alternatively, railroads might raise their rates in order 
to obtain higher revenues from the same quantity of traffic, thus approxi- 
mately maintaining present modal shares.) 

It is important to note that railroads would not have an entirely 
free hand in lowering rail rates or even in maintaining them at their former 
levels, since the Interstate Commerce Commission (ICC) could require rail 
rates to rise in proportion to increases in water rates. The ICC could refer, 
for justification of such action, to its Congressional mandate called the 
National Transportation Policy. It appears as the preamble to the Inter- 
state Commerce Act, and states, in part, that, "It is hereby declared to 
be the national transportation policy of the Congress to provide for fair 
and impartial regulation of all modes of transportation... so administered 
as to recognize and preserve the inherent advantages of each... all to the 
end of developing, coordinating, and preserving a national transportation 
system by water, highway, and rail...." 

3.1.9.4. Recent User Charge Impact Studies . A 1975 General Accounting 
Office (GAO) report concluded that "a fuel tax of about seven cents 
a gallon in 1973 would have fully absorbed the $109 million waterways 



95 

operation and maintenance expense the Corps of Engineers 
incurred. For cotnmercial [waterway] users, this fuel tax would 
have increased their total operating cost by about four percent.... 
Analyses by waterway user groups and Government agencies showed that 
diversion of traffic from the waterways would be sharp if increases in 
barge rates were to exceed 25 percent. If shipping rate increases were 

3/ 

kept below 10 percent... a relatively minimal impact could be expected." 

A 1977 Department of Transportation (DOT) study examined the impact 
of a fuel tax set high enough to recover total expenditures for operation 
and maintenance by the Corps of Engineers and aids to navigation such as 
buoys, markers, lighthouses, and icebreaking by the Coast Guard. The study 
assumed that inland waterway operators would pass the entire amount forward 
in the form of higher transportation rates and that railroads and other 

4/ 

modes would not raise their rates in response to higher waterway rates. 
The study concluded that under a uniform fee, 12 to 15 percent of water- 
borne traffic probably would shift to other modes. However, if seven rivers 
with low traffic volume and high maintenance costs were closed (or continued 

to be subsidized) , the uniform fee would drop by about 23 percent and the 

5/ 

diversion of cargo would be about 10 percent. If a segment fee were 

_3/ For the complete citation to this and the other studies referred to 
in this section, refer to the last subsection, entitled "References". 

4/ Traffic shifts to railroads, pipelines and trucks would be smaller 
if these assumptions are relaxed. 

5/ The seven rivers are listed in footnote 8. 



96 

levied, about 10 percent of waterborne traffic would shift to other 
modes . 

A study completed in 1976 for the Corps of Engineers, using the 
same two major assumptions as the DOT study stated above, concluded that 
a fuel tax set high enough to recover 50 percent of Corps of Engineers 
and Coast Guard operation and maintenance expenditures would reduce water- 
way traffic by 5.5 percent and a fuel tax designed to recover 100 percent 

6/ 

would reduce waterway traffic by 7.1 percent. Segment-specific fees to 
recover 50 percent would reduce waterway traffic by 8.6 percent and 100 
percent recovery would reduce waterway traffic by 9.5 percent. 

Water-served utilities generate large percentages of the electricity 
in every State through which the Upper Mississippi, Illinois, Tennessee, 
and Ohio rivers pass. Utilities located on waterways receive most of their 
coal from barges. The DOT study found that waterway user charges would 
cause little, if any, shifting of waterborne coal traffic to rail transpor- 
tation because the construction of new or expanded rail unloading facilities 
would cost more than the user charges. The DOT study estimated that the 
higher delivered prices of commodities would be "in fractions of one per- 
cent, although certain commodities may experience slightly larger in- 
7/ 

creases." User charges would add about one percent to the price per ton 



6^/ The study was done by the Arlington, Virginia office of CACI, Inc. - 
Federal, a consulting firm. 

y Vol. I, page 8 of the DOT study. See also vol. I, page XI-8. 



97 

of coal delivered to utilities and as a result electricity prices would 
be expected to rise only a fraction of a percent. 

The DOT study estimated that no intermodal shifts of coal traffic 
would result from a segment-specific fee, but CACI estimated a 9 .4 per- 
cent shift. DOT predicted that long distance waterborne hauls of crude 
oil would decline by 10 percent and that waterborne hauls of petroleum 
products, other than residual oil, would decline by 25 percent. The DOT 
and CACI studies indicated that a fuel tax would not drastically shift 
inland waterway traffic to other modes. A segment toll, however, while 

having only a small impact on lower Mississippi River traffic, would 

8/ 

virtually eliminate traffic on a number of other river segments. 

Neither the DOT nor the CACI study indicated that levying waterway 
user fees would restrict seriously the flow of coal and petroleum to con- 
suming areas, but rather that it would modify, to some extent, the modal 
choice and source of supply. 

3.1.9.5. Fuel Efficiency of Competing Modes . Although opponents 
of waterway user charges state that water transportation is much 
more fuel efficient than competing modes, this position is not supported 
by the findings of the GAO and CBO studies. The GAO report concluded 
that a beneficial result of levying a waterway user charge would 

8^/ Both DOT and CACI identified the Allegheny; Apalchicola-Chatta- 
choochee-Flint ; Arkansas; Black and Ouachita; and the Kentucky 
systems. In addition, the DOT study identified the Pearl River 
and the Missouri River while the CACI study identified the Ala- 
bama-Coosa, and the Black Warrior-Tombigbee-Mobile systems. 



24-786 O - 78 - B 



98 

be a slight improvement in the energy efficiency of transportation under 

certain conditions as traffic shifted from barge transportation to rails 

and pipelines. The CBO study compares the results of eleven studies of 

fuel efficiency by waterway, pipeline, railroad, and truck and concluded 

10/ 

that there is "at best a marginal fuel advantage for barge over rail." 

3.1.9.6. General Energy Policy Problems . General energy policy 
questions raised by the waterway user charge issue which are addressed 
by the above discussion include the following: (1) Is a segment toll 
better or worse than a fuel tax? (2) Will waterway user charges disrupt 
the transportation of coal and petroleum? (3) Will they cause serious 
inflation? (4) Will they improve or reduce fuel efficiency in trans- 
portation? (5) Will they jeopardize water transportation as a viable 
mode of transportation? 

A short response to each of these general energy policy problems 
can be given on the basis of the above discussion. In response to the 
first question, a segment toll would dramatically demonstrate the econo- 
mic viability (or lack of it) of individu.al river segments. However, 



9/ Comments critical of the GAO position are contained in Federal agency 
reviews of the preliminary draft of the GAO report. These agency re- 
views appear on pages 30-52 of the GAO report. 

10/ On pages 17 and 18 of the CBO report there are several significant 
points, too long for inclusion here, with respect to available data 
on the fuel efficiency of different transportation modes and with 
respect to several possible alternatives designed to promote fuel ef- 
ficiency in transportation. 



99 

there may be other considerations for continuing to maintain commercial 
navigation on some or all of the high cost (compared to volume of traf- 
fic) river segments. For example, an expensive recently-completed dam 
such as the Bankhead Lock and Dam on the Warrior River, which might not 
need replacement for 40 or 50 years, might not be able to generate suf- 
ficient revenues to cover even operation and maintenance expenses. 
Should that new facility be closed? 

In response to the second general energy policy problem stated above, 
the above discussion suggests that waterway user charges will not disrupt 
the transportation of coal and petroleum, although as much as 10 to 15 
percent of waterborne traffic might be shifted from the inland waterway 
system to other modes. Third, the impact on finished goods likely would 
be a one-time upward price adjustment of less than one percent for most 
commodities, although certain commodities may experience slightly higher 
increases. Fourth, the overall fuel efficiency of transportation would 
not be significantly affected by any resultant modal shift. Fifth, a loss 
of up to 15 percent of barge traffic is far from insignificant, but most 
observers likely would not consider that a loss of traffic of that magni- 
tude would make inland waterway transportation a nonviable mode of 
transportation . 

It should be noted that the level of waterway user charges discussed 
above will not be high enough to recover any new construction expenditures 
by the Federal Government. Secretary of Transportation Adams, in testimony 
before the House Ways and Means Committee, in July 1977, stated that the 



100 



Administration would accept either a fuel tax or a combination of a fuel 
tax, fees and tolls. The Administration goal was to recover 100 percent 
of operating and maintenance expenditures and 50 percent of Federal con- 
struction expenditures. If a fuel tax alone were relied upon to do this, 

it would have to be approximately 40 cents per gallon. The studies dis- 

U/ 

cussed above assumed a fuel tax of 28 cents per gallon or less. 

None of these studies estimated the traffic impact of a fuel tax of 

40 cents per gallon, thus, it is difficult to predict the impact of a fuel 

111 

tax of this magnitude. It seems likely, however, that the Congress will 
enact a fuel tax (above or in conjunction with other fees and tolls) which 
is somewhere between (the equivalent of a) 40 cents per gallon and the 6 
cents per gallon fuel tax in the House passed bill, H.R. 8309. The Con- 
gress is likely to require one or more studies of the impact of the levy 
on commercial waterway traffic and on commercial waterway users, and thus 
there would be a legislated information gathering mechanism to guide the 
Congress in future deliberations on the question of what is an appropriate 
level of waterway user charges. 



11/ The range considered in the various studies are as follows: DOT, 
16 to 22 cents per gallon; CACI, 12.8 to 27.8 cents per gallon; 
and GAG, seven cents per gallon. 

12^/ The Department of Transportation estimates that the cost of moving a 
bushel of wheat to export piers at New Orleans from the Mississippi 
River area which originates the heaviest grain shipments (between 
Burlington, Iowa, and Minneapolis, Minnesota) would rise between 
three and four cents with a blanket fuel tax of 40 cents per gallon, 
and between two and three cents with a segment toll. See page 16 of 

' Secretary Adams' testimony before the House Ways and Means Committee 
(The complete reference is in the subsection entitled "References".) 



101 



References 



American Enterprise Institute for Public Policy Research. 
Waterway User Charges. Washington, [1977] 28 p. 

CACI, Inc. — Federal. Potential Impacts of Selected Inland Water- 
way User Charges. Prepared for the U.S. Army Corps of Engi- 
neers. Arlington, Virginia, 1976. Various pagings. 

U.S. Congress. House. Conmittee on Ways and Means. User Taxes for 
the Inland Waterways of the United States. Hearings conducted 
July 21 and 22 , 1977. Washington, U.S. Gov't. Print . Of f ice , 
1977. Serial number 95-29. 445 p. 

U.S. Congressional Budget Office. Financing Waterway Development: 

The User Charge Debate; a CBO Staff Working Paper. Washington, 
U.S. Govt. Print. Off., 1977. 46 p. Written by Craig Roach. 

U.S. Department of Transportation. Modal Traffic Impacts of Water- 
way User Charges; Staff Study. Washington, 1977. 3 vols, vari- 
ous pagings. Written by David L. Anderson, Robert W. Schuessler 
and Peter A. Cardel lichio . 

U.S. General Accounting Office. Factors to be Considered in Setting 
Future Policy for Use of Inland Waterways. Washington, Nov. 20, 
1975. RED-76-35. 56 p. 

U.S. Library of Congress. Waterway User Charges. Washington, 1976. 
23 p. Written by Louis Alan Talley. 



102 



3.1.10 Natural Gas Pipelines — The Impact of the Natural Gas Shortage 
on their Future */ 

Harbingers of change have appeared for the interstate natural gas 
pipelines of the United States in the wake of the ongoing shortage of natural 
gas. Ending decades of rapid growth in pipeline mileage and capacity, 
the shortage has required a new Federal presence in the allocation of 
available gas to users and prompted a series of administrative actions 
and legislative enactments which provide precedents for great change in the 
industry's structure and mode of operating. If a continuing gas shortage 
leads to the continuing implementation of these recent practices and author- 
ities, the natural gas pipeline industry will change markedly in character 
and new problems will arise. 

3.1.10.1. Background The natural gas pipeline industry is a fully 
regulated private enterprise and has been since the passage of the Natural 
Gas Act of 1938. Under the Federal Power Commission and now under its 
successor, the Federal Energy Regulatory Commission, interstate gas pipeline 
companies have been required to obtain regulatory approval in the form of 
certificates of public convenience and necessity before beginning, expanding, 
contracting, or ending interstate sales of natural gas for resale. The 
rate at which gas is sold to distributors is prescribed, as is the price at 
which gas can be purchased from producers. The financial structure sup- 
porting each company is essentially controlled, and a regulatory accounting 
system is prescribed by a standardized format facilitating uniform application 
of utility principles. 

Pipelines traditionally contract to buy gas from producers, own it while 
it is within the pipeline system, and contract both with distribution companies 

*/ Prepared by John W. Jiraison, Analyst, Environment and Natural Resources 
~ Policy Division. 



103 

and individual large consumers to sell the gas. (In this, they differ 
greatly from oil pipelines [see 3.1.11].) They operate as independent 
companies, dealing individually with gas producers and customers, and 
transact business freely, within the range of price and nondiscriminatory 
behavior constraints. Almost all of their supplies are presently averaged 
and sold at a rolled-in commodity price to their customers. 

This traditional pattern of actions has changed greatly since the 
natural gas shortage became the spectre hanging over the gas industry. 
1978 will be the tenth straight year of decline of the total proven re- 
serves of natural gas committed to interstate pipelines. Production is 
closely related to the reserve base, and began falling as early as 1971 
for some pipelines. This led to the first need on the part of pipelines 
to curtail deliveries to firm customers as well as interruptible customers 
during periods of peak demand. Such curtailments have now grown to the 
point that only 10 of the 50 major interstate natural gas companies were 
anticipated by the FPC to meet all their firm requirements for natural gas 
during the 1977-78 heating season. More than half of these 50 pipelines 
will curtail more than 10% of their firm demand. 

The fall of reserves committed to interstate pipelines is related to 
the prices allowed by the FPC for gas purchases by the interstate pipelines, 
as well as to the overall decline in availability of reserves of natural gas. 
Unregulated purchasers within the producing States have obtained the com- 
mitment of virtually all new reserves of natural gas onshore, since the begin- 
ning of this decade of natural gas decline, because they were able to pay a 
higher price for it than interstate pipelines were allowed to pay. At first 
this price increment was narrow but, since the oil embargo unregulated prices 



104 

have multiplied to reach equivalency with other fuels because dwindling 
conventional gas resources in producing States could not supply the demand 
for natural gas in those States alone at lower prices, despite a vigorous 
exploration effort. Regulated prices have also jumped in a futile attempt 
to outbid intrastate buyers for the available gas. 

Because higher regulated wellhead prices have failed so clearly as a 
means of attracting new long-term supplies, and because new offshore sup- 
plies (automatically committed to interstate commerce by virtue of their 
origin on Federal lands) have not been sufficient to prevent further contraction 
of deliveries, attempts to allocate the interstate shortfall have been found 
necessary. Congress, despite serious legislative efforts in the 92nd, 93rd, 
94th, and 95th Congresses, has not yet modified the basic requirement of the 
Natural Gas Act, as interpreted in the 1954 Phillips case by the Supreme 
Court, that producers of natural gas must sell at a regulated price to inter- 
state pipelines. Hence, administrative actions which could be defended 
as within the overall legislative framework were the sole alternative. 

Such administrative actions have prescribed novel forms of purchases 
by pipelines from producers, a different relationship of pipelines toward some 
of the gas they have carried, and different treatment of pipeline customers. 
Although none have reformed the wellhead pricing situation, statutes have 
been passed which set new precedents concerning relationships between 
pipelines. Other pending legislation would provide a basis for pipeline 
movement of distributor-owned gas. Taken together, these administrative 
and legislative actions may change the face and function of the U.S. natural 
gas pipeline industry. 



105 

3.1.10.2. Emergency Sales . One of the major administrative devices 
used to enable pipeline companies to obtain additional natural gas to make 
up for the falling deliveries from their own committed reserves was the 
allowance of emergency purchases. 

Beginning in 1971, producers were permitted by the FPC to contract with 
pipelines for 60 or 180-day emergency sales or for limited term sales of 
one to three years, all at above the normal regulated prices. Although the 180- 
day sales were later ruled illegal, and the limited term sales were briefly 

forbidden between the issuance of the first national area rate proceeding 

1/ 

and a later opinion on rehearing of the same case case, emergency and 
short-term sales have been an alternate means of selling natural gas into 
interstate commerce virtually since the shortage began. During parts of 1972, 
1973, and 1974, more sales were made under the short-term and emergency 
procedures than the long term sales that have always provided pipelines the 
base of supply that they required for the security of their customers. 

Under the Emergency Natural Gas Act of 1977 (P.L. 95-2) emergency 
purchases were allowed from February 1 to August 1, 1977 at prices negotiated 
between the pipeline and the producer. In practice, the FPC did not approve 
transactions above $2.25/mcf. 

Emergency purchases are desirable from the standpoint of natural 
gas producers for two reasons: (1) they provide a price above regulated 
interstate levels, in fact a price equal to deregulated prices; and (2) 
they are for short periods with pre-granted abandonment, so that they do 

]_l FPC Opinion 699, June 21 , 1974 rescinded limited term contract author- 
ity; FPC Opinion 699-B, Sept. 9, 1974, reinstated it. 



106 

not carry the onus of indefinite Federal regulation and can be recom- 
mitted later at the higher market prices likely to prevail. 

From the pipeline's standpoint, however, these factors constitute 
disadvantages. A major reason for requiring long-term sales was to make 
certain that the expensive gathering or interconnecting facilities installed 
to bring the gas into the pipeline system, and added to the pipelines' rate 
base paid for by customers over of period of many years, would have an 
economic value over an equal period of years, because the long-term sales 
would be bringing gas to the pipelines through them for that long. Al- 
lowing the addition to a pipeline rate base of facilities required for an 
emergency or short-term sale means that customers will be paying the true 
costs of the gas not only at higher than regulated prices while the sale is 
taking place, but also in the cost of the facilities which is being amortized 
even if they are not used after the emergency sale period is completed. 
Although the FERC still retains the power to deny a sale if the required 
facilities are too expensive, and would be reluctant to approve such con- 
nections for a small amount of gas, the shortage and unavailability of long- 
term supplies put the pressure on the FERC to be lenient . 

The lack of certainty of availability or price of emergency natural gas 
over a term of several years is a problem to both pipelines and their 
customers. It is probably reflected in the interest paid for new indebtness 
by both, which again adds to higher costs. To have a large part of the 
pipelines' natural gas supplies coming from such short-term deals is to 
make the natural gas industry and its customers hostage to the swings 
of the market, and changes the basic character of the supply base for 
pipeline operations. 



107 

A recent General Accounting Office report has indicated that emergency 

purchases were routinely used, contrary to the intention of the Emergency 

Natural Gas Act, to continue deliveries to lower priority customers, rather 

2/ 

than strictly to prevent curtailment of high priority customers. In 
addition, emergency purchases have been allowed sometimes to be "tacked" together 
so that sales at the higher prices have continued for longer terms than 
stipulated by the procedure. 

Given the relatively overwhelming market power of producers during 
the sellers' market conditions prevailing during the shortage, it is 
quite likely that in the event of deregulation the number of long term 
contracts would drop relative to short-term contracts which are more in 
producers' interests. This would be contrary to the interests of stability 
in both supply and costs for the pipeline system. Deregulation bills such 
as S. 2310, passed in October 1977, by the Senate, which required long-term 
contracts if deregulated prices are to be obtained for sales from offshore 
leases, would seem to avoid this problem, but many deregulation approaches 
would not . 

3.1.10.3. Price Deregulation. In addition to the higher prices passed 
through, higher costs encountered and shorter supply contracts negotiated, 
the effects of deregulation of natural gas on the pipeline industry would be 
several . 

The ability to engage in price competition for new supply would 
lead to enhanced ability to bid for new gas onshore. Interstate pipeline 

Ij OTA's Report to the Congress, Emergency Natural Gas Purchases: Actions 
Needed to Correct Program Abuses and Consumer Inequities, January 6, 1978, 
END-78-10. 37 pages 



108 

connections onshore would be made to new and recent fields where only intra- 
state pipelines have recently been built. Careful assessment of relative 
fuel prices in pipeline markets would be generated by pipeline management, 
and recognition would be sought of the upper limits of new wellhead prices 
that could be paid without losing customers at the furthest end of the pipe- 
line to other fuels. Pipelines would be forced to begin balancing the neces- 
sity of keeping customers on the system against the necessity of adding to 
supplies at market prices which would drive marginal and distant customers away 

Pipelines which were built to deliver gas which cost 15c per Mcf at 
the wellhead, a common price in the 1950' s and 1960's, were very competitive 
throughout the Nation. Those same pipelines may not be able to survive sel- 
ling gas that now may cost from $2.50 to $4.00 per Mcf after deregulation, 
especially when their own substantial costs must be added for customers 
in New England or other points far from the producing fields. The distance 
at which natural gas can be delivered from the traditional producing fields 
and be competitive with other fuels would begin to shrink. 

The remaining customers would begin to bear the costs of the pipelines 
rate base which were no longer contributed by customers further up the pipeline 
who had been driven to alternate fuels. This would accelerate the contraction 
of gas-competitive areas. The higher natural gas prices following deregulation 
would thus have the effect of reducing the competitiveness of natural gas 
in those consuming areas most distant from the producing fields, and would 
put pressure on pipeline systems to maintain the operation and financial 
viability of their furthest extensions. Supplemental gas sources such 
as LNG, SNG from naphtha, and other sources of substitute natural gas are 
thus becoming popular among these pipeline system serving such areas. 



109 

because they promise to sustain portions of the gas market which may be 
less competitive at deregulated natural gas price levels. 

The other major effect anticipated for deregulation in addition to 
higher prices is, of course, greater supply. This is by no means certain to 
be the case: numerous experts have predicted that at best deregulation 
will only add enough new reserves to slow the current production decline, 
but will not reverse it. If, however, supplies of natural gas do increase, 
at high prices, the demands on pipeline capacity and throughput configuration 
may be significant. It might be that pipelines would desire to expand relative- 
ly short-haul capacity to serve gas-competitive markets even while being 
forced to underutilize capacity in areas where higher-priced gas cannot 
compet e . 

3.1.10.4. Common Carriage of Natural Gas . Unlike oil pipelines, 
railroads, regulated interstate truckers, and some water carriers, natural 
gas pipelines have never been common carriers. Rather than holding them- 
selves out as transporters to any person with natural gas desiring to have 
it moved from point to point over a route served by the pipeline, gas pipe- 
lines have instead bought the natural gas and sold it under contract to users, 
under an obligation to provide utility service where so ordered by Fed- 
eral authorities. 

During the shortage, pipelines were unable to fulfill this service 
obligation to all customers for lack of supply. Administrators looking 
for ways to permit market prices to be paid for natural gas to expand sup- 
plies available to the interstate market conceived of the idea of allowing 
industrial customers who would otherwise be curtailed to purchase gas direct- 
ly themselves, at unregulated prices, and to have it carried to them for 



no 

as much as two years via an interstate pipeline. They would pay the pipeline 
a transportation charge. Embodied in FPC Order 533 issued August 28, 1975, 
those industrial customers were limited to purchases from onshore areas, 
and the Commission reserved the ability to pass on each transaction individually 
in reviewing a pipeline's application for a certificate to engage in the 
transportation. The FPC specifically ruled out allowing distribution utilities 
and other resale customers the opportunity to use such a means of obtaining 
gas, but the statement implied that if it had wanted, the FPC could have allowed 
all pipeline customers to participate. 

The effect of Order 533 was to enable pipelines to serve gas to customers 
who would otherwise have been curtailed, without reducing service to others. 
It accomplished this, however, by changing the basic character of service 
from the traditional utility mode to a contract carrier mode. It constituted 
an end run around the problem of pipelines competing with unregulated intra- 
state buyers at regulated prices, but opened the door to a different service 
configuration for the natural gas industry. 

Order 533 sales were only minor at first, primarily because industrial 
customers were not heavily curtailed during the winter of 1975-76. Their 
popularity grew, however, during the winter of 1976-77, and as of Nov. 30, 
1977, there were 135 transactions, some involving multiple industrial plants, 
which had received Commission approval . The Federal Energy Regulatory 
Commission, successor to the FPC, has recently announced that the program 
is being extended, although additional constraints are likely to be added 
to such arrangements. 

While the amounts of natural gas carried under arrangements is still 
very small, the precedent act by this program is important and a wider use 
of pipelines in such a manner should be examined. 



Ill 

The next step beyond the currently permitted transactions of this 
type may be perceived in a provision of the Outer Continental Shelf Lands 
Act Amendments of 1977, a provision which was in the version passed by the 
Senate and reported to the House of Representatives. Section 503 of both 
bills, would have required the FPC to permit the transportation interstate 
of any gas developed directly or indirectly by a local distribution company 
on the OCS. The gas would not be subject to curtailment by the pipelines 
carrying it, or allocation to other service areas. The stated purpose of 
this provision in the Senate and House Committee reports was to increase 
competition in OCS lease bidding by making it possible for distribution 
companies to participate without risking the loss of the gas developed to 
others who had higher curtailment priorities. 

This provision differs from Order 533-type arrangements in that it fo- 
cuses on OCS lands, where interstate pipelines already have exclusive access 
to developed natural gas, rather than on onshore lands, where regulated 
prices have kept interstate pipelines from competing. As such, this could 
be seen as more of a threat to intestate pipelines' supplies than Order 533- 
type arrangements. It could be argued that the interstate customers would 
be better served by allowing their distribution companies to compete where 
their pipelines cannot, rather than in the sole province where they can. 
As a statutory provision, this amendment would not be subject to court re- 
view under the Natural Gas Act of 1938, as would the same provision or another 
action taken administratively. Although the House and Senate reports indicate 
that "direct or indirect" development is intended to refer to both subsidiary 
and affiliated production enterprises of the distribution company, there is 
no doubt that production from any lease where the distribution company was 



112 

even a minor participant would qualify to be transported under the terms 
of the amendment. It is possible that gas produced from any interest 
obtained, even after discovery had been made but before production had com- 
menced, would also qualify. It is thus likely that a substantial part of 
gas to be developed offshore would be precommitted by this provision to 
certain areas of the Nation, and would be carried by pipeline on a for- 
hire basis similar to gas carried under Order 533. 

If the concept of pipelines carrying natural gas owned by others is 
carried to the logical extreme, and all pipeline customers could arrange 
such purchases and transportation, what would be the effects? 

It is now clear, that, despite the reluctance of pipelines to engage 
in such arrangements, that they are administratively feasible. The deliveries 
of gas to a customer from the pipeline can be directly gauged by the deliveries 
of the producer with whom the customer has contracted so that the other 
gas supplies of the pipeline are not affected. If the customer's supplier 
cannot deliver the gas to the pipeline, the customer itself can be forbidden 
to take extra gas from the pipeline's general supplies. This can be enforced 
by means of penalty payments for taking more gas than has been contributed 
by the taker. Because gas is a totally fungible commodity, when metered to- 
reflect Btu differences, it does not matter that the actual physical 
gas removed by the customer may not be from the exact same wells that the 
customer's producer operated. 

If such arrangements became the rule rather than the exception, with 
all pipeline customers encouraged or required to contract for their own sup- 
plies, a much greater administrative burden would be placed on pipelines 
to oversee deliveries to and from the pipeline with more regularity and 



113 

precision. But the costs of such a burden could be assessed against the 
customers requiring it as part of their payment to the pipeline for 
transportation, and sufficient flexibility and dependability would probably 
be present to make a pipeline operated in that manner workable. Oil 
pipelines, for example, operate this way with the added complication of being 
required to deliver the exact same liquids to shippers that they put into the 
pipeline unmingled and undiluted. 

The motive for allowing more widespread or universal use of the Order 533- 
type of transportation arrangement might be the same as the original motive: 
to enable more gas to flow to interstate purchases without a legislatively 
enacted deregulation of natural gas. Court challenges to Order 533 were 
unsuccessful; the chances of reversal would be greater if the gas were being 
resold in interstate commerce. It is not inconceivable that such sales would 
survive court review, and they might also mitigate some objections to general 
deregulation. 

Consumers could be argued to have better protection from market abuses 
than under full deregulation because those negotiating the field prices would 
either be consumers themselves or those directly serving consumers, rather 
than pipelines which could be argued to have other interests than those of 
their ultimate customers. Distribution companies negotiating with producers 
could do so subject to State regulatory commission authority. Small distri- 
bution companies such as municipal utilities, small industrial users, any 
other customer without the capacity to negotiate in the producing fields 
for gas, or any customer who could not afford market-level gas prices or who 
refused to pay deregulated price levels, could rely on those supplies still 
owned by the pipeline company and those obtained by the pipeline on Federal 

24-786 O - 78 - 9 



114 

lands or from other sources, subject to the same curtailments and limitations 
and service obligations as now cover essentially all the gas in the pipe- 
line. The pipeline industry could gradually relieve itself of the burden 
of responsibility for contracting for new supplies as its customers began 
to contract for their own. The practical difficulties of operating a 
pipeline simultaneously as a utility and as a transporter of gas owned 
by customers would be different in degree but not in kind from those 
already solved in the administration of Order 533. The length of contract 
terms, price, and timing of deliveries could be negotiated between the 
customer and the producer directly, subject only to the capacity of the 
pipeline. During peak periods, if substantial additional gas began flowing 
through interstate pipelines, access to pipeline capacity might have to 
be prioritized among customers in the same way that curtailments are 
now managed, but this is an unlikely problem given current spare capacity. 

Summarizing, it appears that Order 533 has opened the door to a dif- 
ferent mode of operations for interstate gas pipelines: operations in the 
nature of common or for-hire transportation of natural gas owned by customers. 
Section 503 of the pending OCS Lands Act Amendments of 1977, which has passed 
the Senate and been reported in the House, would also require such service 
from for distribution companies who obtained or produced gas on the OCS 
interstate pipelines. If made available universally, and certainly if 
encouraged, the practice of pipelines moving customer-owned natural gas 
and distribution-company owned natural gas directly to their plant or city-gate 
receiving facilities in exchange for payment of transportation costs would 
change the basic pattern of operation for this major form of energy trans- 
portation. Moreover, it could serve as a form of deregulation of natural gas 



115 

prices which would have a different form and character, and perhaps a dif- 
ferent political reception than those proposals which have been considered 
before. Although it certainly could not be said that there is any current 
momentum in the direction of a change of this sort for pipeline operations, 
the current reality of Order 533 and the possible enactment of the OCS 
Lands Act Amendments including Section 503, justify attention to the ef- 
fects of further movement toward such natural gas transportation practices. 

3.1.10.5. Sharing Supplies — Interpipeline Allocation and "Wheeling " 
of Natural Gas . Traditionally, all pipelines were responsible for obtaining 
their own supplies and for serving their own customers' s needs. In addition, 
when curtailments of natural gas service became necessary in the early years 
of this decade, those curtailments were approved and administered on a pipe- 
line-by-pipeline basis. This led to different categories of uses and dif- 
ferent priorities being served by different pipelines. While pipeline A 
might be curtailing all his customers below category 4 in the FPC's nine- 
priority curtailment scheme, pipeline B might not be curtailing at all, 
or might be curtailing only those customers in category 9. 

The exclusive access of intrastate pipelines to onshore natural gas, 
because of wellhead price regulation on interstate sales, has also led to general 
discrepancies between interstate and intrastate pipelines in the levels 
of service they could maintain to users of different priority classifications. 
Intrastate companies generally serve more expensive gas to users whose 
overall priorities are lower in general than those of interstate pipeline 
customers . 

Interstate pipelines have traditionally sold, exchanged, and moved 
substantial quantities of gas between themselves through a pervasive 



116 

network of interconnections. This has helped to bypass sections of pipeline 
that were out of service, or to enable pipelines to obtain supplies outside 
the purchasing areas of their own systems. 

As the shortage of natural gas has become more critical, suggestions 
have been frequently made that service of natural gas be equalized, 
so that all pipelines curtail the same priority customers, by means of al- 
location of gas among pipeline companies. Allocation among interstate 
companies could be used to assume service to all interstate customers 
equally on the basis of priority, curtailing the same priorities on all 
pipelines. This would tend to take gas from those pipelines which 
had better supply situations or lower priority customers on the average, 
and would require compensation from the customers of the pipeline which 
received the gas. Such compensation would presumably cover both the 
costs of the natural gas to the donor pipeline and a pro-rata portion of 
the donor pipelines' transportation costs. It might also include 
compensation to customers of the donor pipeline, who were curtailed in 
order that the allocation could be made, to cover their costs of alternate 
fuel . 

The interstate pipelines have traditionally opposed such inter-pipeline 
allocation vigorously. The FPC steadily denied that it had the authority 
to order such allocation. Intrastate pipelines, who benefitted by 
not being under Federal regulation in obtaining gas, have strenuously 
opposed any suggestion that some of their gas be allocated to other 
pipelines, interstate pipelines especially, even though their customers 
are of lower priority. In addition, the problems of compensating 
intrastate pipelines and their customers would be more complex because 
of their higher prices. Finally, intrastate pipelines were afraid 



117 

that any connection or sharing of gas with interstate pipelines 

would bring them into the dreaded tentacles of Federal regulation, and 

put them under the Natural Gas Act. 

Despite this opposition by both interstate and intrastate pipelines, 
the fiercely cold weather in December of 1976 and January of 1978 combined 
with the continuing shortage to threaten top priority residential, small 
commercial, and human needs customers with curtailments and loss of ser- 
vice. Such curtailments would have meant great danger to life and pro- 
perty, and were to be avoided if at all possible. It quickly became 
evident that sharing of supplies among pipelines was one of the few 
means available to alleviate the critical situation in short order. 
With cooperation from the pipeline industry, the Administration drafted 
The Emergency Natural Gas Act of 197 7, which was considered, passed, 
and signed into law (P.L. 95-2) in record time. ENGA authorized the 
President to declare an emergency and appoint an Administrator, among 
whose powers was the ability to order pipelines to allocate gas to other 
pipelines who were in jeopardy of curtailing critical priorities. The 
President's Administrator could also order intrastate pipelines to transfer 
natural gas from one interstate pipeline to another interstate pipeline. 
Intrastate pipelines complying with transfer orders would be preserved 
from Federal regulation under the Natural Gas Act. Such transportation 
of natural gas might be called "wheeling" of gas because it is similar 
to the "wheeling" of electricity power which utilities practice. 

In fact, no mandatory allocation or transfer was necessary because 
the severity of the weather eased significantly during February and the 
remaining months of the winter, and because voluntary exchanges, emergency 



118 

purchases, and other actions sufficed to prevent curtailment of top 
priority customers. Since thd emergency, pipeline storage has been filled, 
and numerous large customers have discontinued natural gas use, so that 
there is little likelihood of a similar emergency during the current 
heating season. The ENGA allocation authority lapsed, and a proposal 
to reinstate it for this and succeeding winters which were included in 
the President's National Energy Plan, and offered independently when it 
was clear that the NEP was not going to be enacted, was not acted upon. 

Nonetheless, a national policy was established during the critical 
emergency, a national precedent was set, that basically held that inter- 
pipeline allocation of natural gas would be used if necessary to prevent 
curtailments of critical customers. Presumably, the authority to order 
such allocation will again be enacted if needed, and possibly, enacted on 
a standby basis for whenever it may be needed. 

The President's plan also proposed to include intrastate pipelines 
among those from or to which gas could be allocated, in keeping with 
a central purpose of most gas regulatory reform or deregulation legisla- 
tion — the abolition of separate markets in producing States. 

The shortage is predicted to worsen, and this prediction is unanimous 
if the congressional impass over gas legislation continues. At the same 
time, some gas utilities are clamoring to take on a new high priority 
customers because of their declining industrial sales and increasing flex- 
ibility caused by storage and supplemental supply programs. They also 
realize that residential customers are the last to go to other fuels when 
prices rise as they must. Other users, particularly agricultural and 
food process users, may convince Congress to include them in the highest 



119 

priority class. These factors could combine to increase the likelihood 
of future threats to high-priority customers which would call for inter- 
pipeline allocation. 

Theoretically, it makes little sense to order inter-pipeline allocation 
to protect residential and small commercial customers during periods of 
critical need, but to tolerate great discrepancies among the priorities 
served at other times. If the priority classifications mean anything, 
they could be argued to apply with or without an emergency. Society would 
presumably be better off to institute them on a consistent national basis 
rather than on a pipeline-by-pipeline basis as the circumstances dictate. 
In the alternative, such an equalization of the priorities served might 
be affected by the allocation of discovered gas reserves among gas pipeline 
companies in proportion to their need and priority of service profiles. 
This alternative would preserve the operational independence of the pipeline 
companies, but would have a similarly significant effect on the current 
practice of field market natural gas sales and commitments. 

In conclusion, the allocation of natural gas among pipelines, which 
was thought necessary and was authorized during the crisis of the winter of 
1976-77, may again be required in the future, especially if supplies 
continue to fall and the highest priority classes of customers grow either 
in number or by definition. The logical extreme to which such allocation 
may lead is unified or centrally coordinated supplies of natural gas 
to the pipeline system. This would obviously result in a markedly different 
character for the natural gas pipeline industry. The resistance to such 
a change can be expected to be great, particularly if intrastate pipelines 
are included because of their generally lower priority customers and 
previous complete independence. Nonetheless, the first movement toward 



120 I 

such allocation has occurred, and a worsening gas shortage will generate 
considerable momentum for such allocation and coordination in order to 
mitigate the effects of the shortage on higher priority customers. 

3.1.10.6. Spare Capacity and Depreciation of Pipeline Investment 
Pipelines which are curtailing a significant percentage of their firm 
customers can be presumed to have spare capacity of at least that percentage 
in their existing systems. In fact, most pipelines have never operated at the 
maximum capacity of their systems, because even at the point of peak deliveries 
to firm customers they also served interruptible customers. They had alsol 
built their pipelines to accommodate the continued growth they expected. 
It is thus quite possible that pipelines curtailing firm customers 
by 25% are actually operating at half or less of their maximum capacity. 
As the shortage grows, the customers not being curtailed must pay, 
as a portion of their rates for natural gas, increasing shares of 
the cost of amortizing the rate base of the pipelines. The whole cost 
of the pipeline is spread over a shrinking volume of gas. 

At the same time, many pipelines have sought to have a faster depreciation 
of their facilities reflected in their rates, because their more pessimistic 
view of gas supplies has changed their perception of the useful life of 
their pipeline investments. The salvage value of an abandoned gas pipeline 
is generally zero — the value of the scrap steel is equalled or exceeded by 
the cost of entry, removal, and restoration of the right-of-way. Faster 
depreciation of pipeline investment drives rates up. If the pipeline's 
assessment of the remaining useful life of the facility is wrong, and 
the value is maintained by production of gas from geopressured zones, 
LNG or other supplementals , or conversion to hydrogen, coal slurry 



121 

(see 3.1.16.) or other fuels, then current customers might pay costs of 
the pipeline's investment that should properly be assessed against 
customers later, or that should be refunded if the pipeline is converted 
to another purpose. The development of spare capacity and faster 
depreciation rates thus puts additional rate pressure on pipeline 
customers, whose service costs are at or near those of substitute 
fuels, to convert more quickly to alternate fuels, increasing the costs of 
those who remain. 

The pipeline companies themselves, like all corporate entities, desire 
continued growth and earnings growth. Deterred by the shortage and the 
consequent spare capacity from making large additional investments in pipe- 
line, they are seeking both natural gas-related and other investments. 
They are perhaps the industrial sector most actively interested in sup- 
plements to natural gas such as coal gasification, Mexican gas imports, 
and LNG imports. They are operating their own gas production subsidiaries 
and affiliates. They are also diversifying into non- j urisdictional 
fields . 

The major current problem is the uncertainty of gas supplies, which 
will determine the level of pipeline utilization, and a parallel problem 
of determining the probable consumer acceptance of higher natural gas prices, 
which will inevitably accompany any expansion of gas supply, whether from 
conventional or supplemental sources. 

Another major uncertainty is whether expensive new gas, either from 
conventional sources, or supplemental sources, must be priced incrementally 
to its consumers, rather than being "rolled in" with cheaper domestic 
conventional gas to keep the cost down to users. The natural gas bills 
passed by both Houses of Congress in the first session of this Congress, 



122 

despite their stark policy differences on other matters, contained very 
similar provisions in favor of incremental pricing of new natural gas 
to lower priority users. If incremental pricing should be adopted for 
such conventional supplies, then logic would seem to require incremental 
pricing for still more expensive sources. It is unclear whether such 
expensive sources of new gas as Alaskan gas (recently estimated to 
cost as much as $5.25 per Mcf delievered by the President of the group 
planning the pipeline — see 3.2.6), Mexican gas (See 3.3.6), LNG (see 
3.5.12), coal gasification, or gas from such exotic domestic sources 
such as Devonian shale, geopressured acquifers, and tight gas sands 
will be bought by consumers at their full cost plus transportation 
and distribution. In fact, numerous planned supplemental gas projects 
are likely to be unfinancable if incremental pricing is required. 
The future use of pipeline capacity and future consumption of natural 
gas will be greatly affected by the resolution of the incremental 
pricing policy debate. A high degree of uncertainty will prevail 
until the question is anwsered. 

The motivation for incremental pricing of new gas and supplemental gas 
sources is usually stated to be a desire to focus the higher costs of new 
sources on those users who have both paid lower rates in the past as a functior 
of declining block rate structures, and who can presumably convert to other 
than gaseous fuels and should be encouraged to do so. In addition, "rolling 
in" higher cost gas supplies is seen by advocates of incremental pricing 
to constitute a subsidy to such higher cost supplies, allowing them 
to be sold at a lower price than their cost, and forcing small users 
such as homeowners to contribute to the cost of natural gas that is being 



123 

added to the system in order to keep industrial customers on line. Finally, 
advocates assert that pipelines would have little incentive to bargain 
for lower natural gas prices if such prices can be rolled in and the 
resulting average price is below competing fuel prices. 

The natural gas industry and others who oppose incremental pricing 
note that various natural gas prices have always been "rolled in" and the 
commodity charged to all consumers equally. They point to the administrative 
problems of billing differentially depending on the use and source of 
the gas. They emphasize the likelihood that residential consumers as 
well as industrial consumers may come to rely on supplemental sources 
for their gas in the future; sources that will not come into being 
without rolled-in pricing. 

Whatever the arguments, it appears to be undisputed that incrementally 
pricing new natural gas will hasten the decline of industrial load, and 
incremental pricing of supplemental sources will drastically reduce the 
likelihood of their early development. 

In conclusion, the growing spare capacity of natural gas pipeline 
systems, the desire to accelerate their depreciation, and the incremental 
pricing controversy for both new natural gas and supplemental gaseous 
fuel supplies of all sorts, combine to yield great uncertainty about the 
future use of the multi-bilion dollar gas pipeline network. Despite 
the boosterism of some, particularly in the gas utility sector, the 
natural gas business is threatened by the shrinking supply, rising 
prices, and uncertain policies of government and reactions of consumers. 



124 

3.1.10.7. Conclusion . The natural gas shortage has brought the 
natural gas industry face to face with major changes in its way of 
doing business. Beset with uncertainty about Federal pricing policy at 
the wellhead, and uncertainty about the supplies available regardless 
of pricing policy, the pipelines have looked for alternative ways to 
absorb their spare capacity. But supplemental projects are threatened 
by the spectre of incremental pricing. The customer response to higher 
gas prices is unknown, but already large gas users are switching perma- 
nently to other fuels in response to curtailments, prise rises, and govern- 
ment encouragement . 

The devices used to mitigate the shortage — emergency purchases, 
allocation among pipelines, and transportation of custoraerowned gas 
and others — are marked departures from the way of doing business that 
gas pipelines have traditionally practiced. Yet a continuing shortage, 
and continuing congressional stalemate on long-term natural gas policy, 
may force not only the continuation of such administrative devices, but 
their expansion or permanent adoption. The shortage may, in short, lead to 
major changes in the operations and character of this major form of energy 
transportation . 



125 



3.1.11 Changes in the Oil I'ipeline Industry's Regulatory and Organizational 
Structures . 

Oil pipelines have been under Federal regulation for over 70 years. 
During this period, there have been innumerable proposals to change the reg- 
ulatory format utilized by the Interstate Commerce Commission (ICC), the 
legislation which supports that format, and the industrial organization of 
the pipeline business, which tends to be dominated by producer interests. 
The following discussion relates the legal history which underlies oil 
pipeline regulation, the practical differences between this form of regulation 
and that of traditional utility type natural gas pipeline regulation. 
It also considers the controversial matter of divestiture of oil pipelines 
from an integrated oil company ownership. 

3.1.11. 1 . Legislative Background . *_/ 

The purpose of this section is to provide a brief description of the 
historical development and the present regulations of oil pipelines by 
the Federal Government . 

Almost as an afterthought of congressional interest in railroad reg- 
ulatory reform, the major Federal enactment providing jurisdiction over 

interstate petroleum pipelines was incorporated into the legislation im- 

1/ 

proving railroad regulation. The Hepburn Act remains today the primary 
Federal statutory enactment over oil pipelines, and its legislative history 
is most instructive in understanding present oil pipeline regulation. 

The Lodge Amendment . On May 4, 1906, as amendments to the railroad 
reform bill were being taken up on the Senate floor. President Theodore 

*/ Prepared by Robert D. Poling, Legislative Attorney, American Law Division. 
1/ 34 Stat. 584 (1906), 49 U.S. Code Section 1, et seg. 



126 



Roosevelt sent a message to the House and Senate transmitting a report 

by the Commissioner of the Bureau of Corporations of the Department of 

Commerce and Labor on the subject of transportation and freight rates in 

the oil industry. That message provided in part: 

... that the Standard Oil Company has benefitted enormously up 
almost to the present moment by secret rates, many of these 
secret rates being clearly unlawful. This benefit amounts to 
at least three-quarters of a million a year. This three-quarters 
of a million represents the profit that the Standard Oil Company 
obtains at the expense of the railroads; but of course the ulti- 
mate result is that it obtains a much larger profit at the ex- 
pense of the public. Ij 

Shortly after the communication from President Roosevelt was read 
into the record, Senator Lodge of Massachusetts called for the considera- 
tion of his proposed amendment. As proposed on the floor in modified form, 
the so-called Lodge Amendment brought oil pipelines under the Interstate 
Commerce Act: 

Any corporation or any person or persons engaged in the 
transportation of oil or other commodity, except natural gas or 
water for municipal purposes, by means of pipe lines or partly 
by pipe lines and partly by railroad, or partly by pipe lines and 
partly by water, who shall be considered and held to be common 
carriers within the meaning and purpose of this act .... _3/ 

Senator Lodge offered this explanation of his proposed amendment: 

... Oil is one of the greatest articles of interstate commerce 
carried in this country, and it is now absolutely outside and beyond 
any Government regulation whatsoever ... the oil is brought to the 
trunk lines through small local feeding and gathering lines, as a 
rule. There are practically two great companies that control pipe 
lines engaged in interstate commerce. One is Standard Oil, which 
is said, to control 90 per cent. I do not know whether that is 
correct or not. The other is the Pure Oil. They do not own the 
wells, and they buy the oil of the well owner, and the charge for 
the transportation is taken out of the price, as appears in the 
copies of the certificates and receipts which I have have. 



y 40 Cong. Rec. 6358, 59th Cong., 1st. Sess. (1906). 



V $0 Cong. Rec. 6361, 59th Cong., 1st. Sess. (1906). 



127 



Those well owners are aboslutely at the mercy of the pipe lines. 
I have had cases brought to me, which in this fifteen-minute debate 
I can not enlarge upon, where an independent refinery has been de- 
prived of its supply of oil because it would not agree to the prices 
of the pipe lines. A small well owner is compelled to take the 
price that is offered by the controller of the trunk line.... k_l 

Lodge's argument was premised upon two major points: first, that 
some form of regulatory review be created at the Federal level, and 
secondly, that a regulatory mechanism be created to assure that small 
independent oil producers be treated fairly in the establishment of oil 
pipeline rates. After a discussion of the commodities which should be 
covered by the amendment, with exception written in for natural and arti- 
ficial gas, the Lodge Amendment was adopted by the Senate, by a vote of 

5/ 

74 yeas, nays, and 14 not voting. 

Thereafter, a "commodity clause," prohibiting shipment of company- 
owned oil, was adopted in language that was sent to the Conference Com- 

6/ 

mittee by the Senate. 

In the conference committee, however, the language of the commodities 

clause was changed, without explanation, from a prohibition applicable 

to all regulated common carriers (including oil pipelines) to a prohibition 

7/ 

applicable only to railroads. 

Thus, when final action was taken by both the House and the Senate, 
the commodities clause only prohibited railroads from shipping their own 



4/ 40 Cong. Rec. 6365-6, 59th Cong., 1st Sess. (1906). 
_5/ 40 Cong. Rec. 6373, 59th Cong., 1st Sess. (1906). 
6^/ 40 Cong. Rec. 7017 , 59th Cong., 1st Sess. (1906). 

y House Conference Report No. 5003, 59th Cong., 1st Sess., (June 23, 1906) 
at 4. 



128 



commodities. Had the commodities clause been made applicable to oil pipe- 
lines, it would have required the immediate divestiture of oil pipelines 
from producer and refinery interests. There is, however, every reason to 
believe from the legislative history, that the Congress did not intend 
such a divestiture for it thought that the legislated common carrier status 
would provide an adequate check on shipper-owned oil pipelines and their 
operations . 

The Standard Oil Case . Within six months of the enactment of the Hepburn 

Act, the Roosevelt Administration initiated what was to turn out to be the 

8/ 

first major interpretation of the Sherman Antitrust Act of 1890 in the 

presentation of a suit against Standard Oil of New Jersey, 33 corporations, 

and seven individual defendants, including John D. Rockefeller, on November 15 

1906. The suit charged violations of Section 2 of the Sherman Act and sought 

the breakup of the Standard Oil empire. The three judge panel in the Circuit 

Court ordered the divestiture of control of the many subsidiaries of Standard 

9/ 

Oil of New Jersey in its opinion of November 20, 1909. 

Among other comments the court made this observation about the Sherman 

Act : 

The purpose of this statute was to keep the rates of transportation 
and the prices of articles in interstate and international commerce 
open to free competition. Any contract or combination of two or 
more parties, whereby the control of such rates or prices is taken 
from separate competitors in that trade and vested in a person or 
an association of persons, necessarily restricts competition and 
restrains commerce. The formation or maintenance by competing corpora- 
tions of an association to determine their rates of transportation 



8/ 26 Stat. 209 (1890), 15 U.S. Code Section 1 et seq . 

9^/ United States v. Standard Oil Co. of New Jersey , 173 Fed. 17 7 (Cir. 
E.D. Mo. 1909) . 



129 



the exchange of the stocks or property of competitive corporations 
for the stock or for interests in a single corporation, which 
thereby acquires the power to control the rates of transportation 
or the prices of articles in interstate commerce in which the cor- 
porations were dealing ... are alike declared to be illegal by this 
law. . . 10/ 

This observation confirms the notion that the Sherman Act was perceived 
as a means of regulating monopolistic advantages in transportation, including 
pipelines. Thus, the Sherman Act existed along side the Hepburn Act as 
a second basis of regulating oil pipeline activity. Monopolistic practices 
were regulated by the Sherman Act, and the Hepburn Act established rate 
regulation, but it should be observed that the two were not mutually exclusive 
in jurisdiction. 

On appeal, the Supreme Court of the United States affirmed the Circuit 

n/ 

Court in Standard Oil and thereby established a landmark antitrust decision. 

Apart from the Standard Oil suit, the Federal Government has not success- 
fully undertaken major litigation under the Sherman Act to bring about 
the divestiture of oil pipelines of oil conglomerates. Standard Oil continues 
to be an almost singular attempt at vertical divestiture in the oil industry. 

Hepburn Act Court Case . The first major enforcement action initiated 
against oil pipelines under the Hepburn Act began as an inquiry of the Inter- 
state Commerce Commission in June 1911 to determine whether any of the rates 
and practices of several named oil companies were in violation of the Act. 

At the completion of the inquiry, the ICC ordered the pipelines to begin 

12/ 

filing schedules of rates and charges for transportation of oil. 
10/ Ibid. , at 184-5. 

11 / Standard Oil Company of New Jersey v. United States, 221 U.S. 1 (1911). 
12/ In the Matter of Pipe Lines , 24 I.C.C. 1 (1912). 

24-786 O - 78 - 10 



130 

The pipelines appealed to the Commerce Court arguing that the Hepburn 
Act only applied to pipelines which voluntarily acted as common carriers 
and that the Act was an unconstitutional denial of due process and depriva- 
tion of property without just compensation in violation of the Fifth Amend- 
ment. In Prairie Oil & Gas Co . v. United States , 204 Fed 798 (Commerce 
Court 1913) , the Court had difficulty dealing with the constitutional 
arguments and in part agreed with the pipelines. 

All of the issues in that cause came to the Supreme Court in the Pipe 
13/ 

Line Cases in June of 1914. In a brief opinion for the Court, running less 
than five total pages most of which were devoted to a description of Standard 
Oil business practices, Mr. Justice Holmes concluded that the intent of the 
Hepburn Act was to bring under its regulation interstate oil pipelines regard- 
less of their prior status: 

... while the amendment [the Hepburn Act] does not compel ... 
[oil pipelines] to continue in operation it does requires them 
not to continue except as common carriers. 14 / 

On the constitutional issues. Holmes was even more cursory: j 

There is not taking and it does not become necessary to consider 
how far Congress could subject them to pecuniary loss without com- 
pensation in order to accomplish the end in view. 15 / 

Although there have been other Supreme Court determinations on many 

of these same or similar constitutional consideration respecting oil pipe- 

lines, this view established by Justice Holmes continues to support 

the Hepburn Act . 

137 The Pipe Line Cases , 234 U.S. 548 (1914). 
14/ Ibid. , at 560. 
Ibid., at 561. 

W See Valvoline Oil Co. v. United States , 308 U.S. 141 (1939); Champlin 
Refinery Co. v. United States, 329 U.S. 29 (1946); and United States 
V. Champlin Refining Co ., 341 U.S. 290 (1951). 



131 

Shipper-Owned Pipelines . As common carriers under the Hepburn Act, 

oil pipelines which are "shipper-owned" have unique problems in the establish- 

17/ 

ment of non-discriminatory rates. Rates must be just and reasonable 

18/ 

and rebates are prohibited. 

The problem of rate establishment by oil pipelines shipping their own 
oil as "shipper-owners" was first raised in a 1941 suit brought under the Elkins 
Act, 49 U.S. Code Section 43, to enjoin certain shipper-owner pipelines from 
granting refunds, rebates, and offsets against regular tariff charges for 
oil transportation. The complaint, brought by the Department of Justice, 
alleged that returns on the shipment of oil owned by the Atlantic Refining 
Company (and several other pipelines) in its own pipeline amounted to an 
illegal rebate. 

The case was settled with the approval of the court by means of a con- 
sent decree which provided under paragraph III that "no defendant common 
carrier would credit, give, grant, or pay directly or indirectly ... any 
earnings, dividents, sums of money or other valuable considerations derived 
from transportation or other common carrier services which in the aggregate 
is in excess of its share of seven percentum (7%) of the valuation of such 

common carrier's property, if such common carrier shall have transported 

19/ 

... petroleum products for said shipper-owner. " Valuation was intended 
to mean the latest final valuation of the common carrier's property owned 
and used for common carrier purposes as established by the ICC. 

49 U.S. Code Section 1(4) and (5). 
18/ 49 U.S. Code Section 2. 

19 / United States v. Atlantic Refining Company, Civil Action No. 14060, 

U.S. District Court for the District of Columbia (December 23, 1941). 



132 

There are several points which might be generally made about this con- 
sent decree. First, by its own language, the consent decree is applicable 
only to defendant common carriers. Therefore, it would seem that non- 
defendant common carriers are not bound by the express terms of the consent 
decree, and the doctrine of res judicata would seemingly support that con- 
clusion. 

The ICC was neither the complaining party or a named party, as the 

Elkins Act requires that actions be brought by the Department of Justice, 

and there is nothing in the consent decree which imposes any obligation 

on the ICC. Therefore, as a matter of law, the legal criteria for the 

20/ 

actual establishment of rates is unaffected by the consent decree. 
And, even though earnings in excess of the 7% figure may not be returned 
to the parent by the shipper-owned carrier, the earnings may be retained 
under the consent decree. The 7% return on valuation was not established 
by the settlement decree as the basis for the approval of rates to be 
charged. In other words, the ICC was permitted to continue to establish 
rates that were "just and reasonable," even thotigh earnings resulting from 
such rates would exceed the 7% figure. Earnings could be retained and used 
for several purposes as provided in the consent decree. 

In 1959, the Supreme Court reviewed a case brought seeking an interpre- 
tation of this consent decree. In its review, the Supreme Court gave its 

21/ 

approval to this system of limitation imposed by the consent decree. 

20 / See, statement by Victor Hansen, Assistant Attorney General in charge 
of Antitrust Division. "Consent Decree Program of the Department 
of Justice." Hearings before the Antitrust Subcommittee of the Committee 
on the Judiciary, House of Representatives, 85th Congress, 1st Session 
(1957), Part I, Volumes I and II, "Oil Pipelines, : at 4476. 

!}_/ United States v. Atlantic Refining Co. , 360 U.S. 19 (1959). 



133 



The question presented to the court was an interpretation of the means 

of computing the valuation of pipelines under the 1941 consent decree. 

The following excerpt from the case sunimarizes the issue raised: 

From 1941 to 1957 appellees computed allowable dividends 
by taking 7% of the valuation of pipeline property and 
then giving each owner a proportion of this sum equal to 
the percentage of stock it owned. In 1957, however, the 
Government brought this suit against appellees claiming 
that the pipelines were giving, and the shipper-owners were 
receiving, dividends in excess of those allowed by the 
decree. The Government did not contest the valuation 
figures used, but argued, despite the language of the de- 
cree, that only a part of 7% of the valuation could 
actually be made available as dividends to stock- 
holders. The total allowable "dividends", it claimed 
would have to be shared between stockholders and cre- 
ditors. The stockholder's (shipper-owner's) "share" 
of the carrier valuation, so the argument ran, was to 
be the porportion which stock-investment in the carrier 
bore to the carrier's total invested capital (including debt 
owed to third persons) . Seven percent stockholder-dividends 
could only be computed out of this "share" of the sum, 
and could then be distributed to each shipper-owner in 
proportion to its individual stock interest. Only 
in this way, the Government contended, could the consent 
decree' s aim of preventing disguised rebates be ac- 
complished. For only in this way would dividends be 
limited to a "fair" sum: 7% of the current value of what 
each owner had invested in its subsidiary. The trial 
court rejected the Government's interpretation, and 
the United States brought a direct appeal under 32 Stat. 
823. as amended. 15 U.S.C. section 29, 49 U.S.C. 
section 45. 22 / 

The Supreme Court rejected the Government's position. A hypotetical 
example illustrates the difference in interpretation, including the 
Government's view which was rejected. 



22/ Ibid. 



134 



Assuming a carrier has an I.C.C. "valuation" of $10,000,000, 
$2,000,000 of which represents stock investments of $1,000,000 
by each of two shipper oil companies, and $8,000,000 of which 
represents debt because of money borrowed by the carrier from 
others, on the appellee-companie' s interpretation of the decree, 
each of the two shipper-owners would be entitled to "dividends" 
of one-half ( $1 ,000 ,000/$2 ,000 ,000) of 7% of $10,000,000 or 
$350,000. On the Government's new interpretation instead, 
each shipper-owner's "share" would be one-tenth ($1,000,000/ 
$10,000,000) of 7% of $10,000,000 or $70,000, this being 7% 
of each one's actual investment of $1,000,000 in the company. 23 / 

In essence, this interpretation allowed the common carriers to 
distribute earnings on pipeline operations based on valuation which in- 
cluded borrowed money, including money borrowed from the parent or shipper 
As one House Subcommittee report put it: 

The decree, entered on December 23, 1941, largely abandoned 
the original theory of the complaint that any dividends to 
shipper-owners were illegal rebates and instead sought only 
to limit dividends to a fair return on the actual investment by 
shipper-owners. But it did so quite ineptly by the adoption 
of a formula limiting dividents paid out to 7 percent of the 
" shipper-owners ' s share" of the pipeline's "valuation." This 
language made the 7-percent limitation almost completely ineffective, 
since it was applied not to paid-in investment only but to the entire 
valuation of the line, including debt capital. And, since joint 
venture pipelines were increasingly financed by a 90 to 10 debt- 
equity ratio, the difference was quite staggering. Instead 
of a limit of 7 percent of actual investment, the formula per- 
mitted dividends of 70 percent of actual investment. 24 / 

Because Atlantic Refining continues to stand as the major precedent 
relating to shipper-owned pipeline valuation, oil pipelines appear to 
enjoy a very unique form of economic regulation. Although they are 
"common carriers" under the Federal statutes, they are treated dif- 
ferently from other common carriers under those statutes. 



23 / Atlantic Refining , supra , footnote, at 360. 

24 / See p. 8, Anticompetitive Impact of Oil Company Ownership of Petro- 
leum Products Pipelines, A Report of the Subcommittee on Special 
Small Business Problems to the Select Committee on Small Business, 
House of Representatives, 92rd Congress, 2d Sessions (1972). 



135 

And since the rate-making mechanism is divorced from other types of 
economic and antitrust regulation, the picture of oil pipeline regulation 
at the Federal level is fragmented. 

Department of Energy Act . In its efforts to consolidate all of the 

major Federal energy regulatory functions under a single agency, the Con- 

25/ 

gress provided in the Department of Energy Act for the transfer of Fed- 
eral oil pipeline regulatory authority to the new Department of Energy. 
Functions relating to rates and charges for transportation of oil were 
transferred to the Federal Energy Regulatory Commission (FERC), which 
is an independent commission organized within the Department of Energy. 
The residual functions relating to oil pipelines were transferred 
to the Secretary of Energy. 

FERC has the authority to represent itself in lower Federal courts 
independently from the Department of Justice, authority that the Department 
of Energy does not have. With this new authority to regulate rates as well 
as litigate, FERC has the ability to litigate many issues relating to 
economic regulation of oil pipelines, perhaps including issues which might 
in effect dissolve the consent decree in Atlantic Refining . And even though 
the Elkins Act required Department of Justice representation on suits in- 
volving illegal rebating, direct litigation by FERC relating to Atlantic 
Refining may now be possible under Section 402(b) of the Department of 
Energy Act since the matters involve "rates and charges." 

25/ Public Law 95-91, 91 Stat. 565 (August 4, 1977). 
26 / See, Title IV of Public Law 95-91, supra . 



136 

This new consolidated authority to regulate rates and litigate pro- 
vides an opportunity to resolve the disparity between the Atlantic Refining 
consent decree and the practices and procedure of rate-making for shipper- 
owner pipelines. Moreover, the authority could permit a complete review 
of the terms and limitations of the Atlantic Refining consent decree 
particularly with regard to some of the more ambiguous provisions relating 
to the distribution of retained earnings and other matters. 

*/ 

3.1.11.2. Oil Pipeline Regulation versus Gas Pipeline Regulation 
This section discusses and contrasts the Federal regulation of oil 
and natural gas pipelines. Both industries — while operating physically 
similar facilities — have grown up in completely different regulatory 
environments . 

The oil pipeline industry's regulatory framework has evolved from 
a series of laws, court decisions and a consent decree. Interstate gas 
pipelines, on the other hand, were regulated under the Natural Gas Act, 
as interpreted by the courts and Federal Power Commission in a more clearly 
defined way. Both the Hepburn Act and the Natural Gas Act seemingly directed 
the same general regulatory mandate — that rates be set at "fair and 
reasonable" levels and nondiscriminatory tariff procedures be implemented. 
However, the ICC and the Federal Power Commission (FPC) ultimately proceeded 
down very different regulatory paths. 

The Oil and Gas Pipeline Business Contrasted. Interstate gas pipe- 
lines operate as traditional utilities, transporting gas purchased from 
unaffiliated producers, for the most part. The FPC effectively discouraged 



V 3.1.11.2 and 3.1.11.4. prepared by Lawrence Kumins, Analyst, Environment 
and Natural Resources Policy Division. 



137 

pipeline affiliated production for many years by regulating its price at 

actual production cost which was usually lower than the applicable rate 

for non-af f il liated production. Nearly all transported gas is for resale 

to local distribution utilities, which are natural monopolies and are 

generally regulated by state public utility commissions. As utilities, the 

customers of interstate gas pipelines do not generally compete with one 

another, nor does the pipeline ordinarily compete with its own customers . 

Oil pipelines operate in a somewhat different business framework. 

As common carriers, they theoretically hold themselves out to all 

shippers who can meet their minimum tender requirements. While gas pipe- 

1/ 

lines only transport the gas under contract to them, and do not ordinarily 
sell it in competition with others marketing gas, oil pipelines are more 
involved in the crude oil and refined product marketplace which they serve. 
Common carrier oil pipelines must, in theory, transport the oil of firms 
which compete with the pipeline owners. They transport crude supplies for 
refiners with whom their refineries must compete and refined products for 
marketers selling their fuels in the same markets as the pipelines owners. 

The fact that oil pipelines carry commodities for their competitors 
makes their business fundamentally different from that of gas pipelines 
or even other types of common carriers. They are the only form of utility 
(quasi or pseudo utility might be a better descriptive term in the oil 
pipeline case) wherein the utility owners are in competition with their 
customers. It is noteworthy that this situation is unique among trans- 
portation common carriers as well, since other carriers are prohibited from 
carrying products of their own by the commodities clause. 

1/ Some gas — a relatively small amount under FPC Order 533 — is trans- 
ported on behalf of industrial customers in common carrier fashion. 



138 

Gas Pipeline Regulation . Natural gas pipelines are now regulated 
in the Department of Energy by the Federal Energy Regulatory Commission 
(FERC), in a manner which is similar to that of electric utilities. Rates 
are set in such a way that the following cost elements are reimbursed 
the pipeline: 

(i) Actual operating costs; 

(ii) Depreciation — facilities are depreciated down to zero or scrap 
value over their useful lives. Depreciation is based on actual original 
cost of the items involved; 

(iii) Return on investment — two types of returns are reimbursed in 
the pipelines cost of service (upon which tariffs are based). First, 
actual cost of debt is reimbursed. Only true debt service outlays are 
allowed to be included in the cost of service computation; 

Second, return on equity investment is computed. This figure is 
based on the estimated return on equity earned in the industrial sector 
on investments of similar risk. Actual tax liability is also reimbursed 
here, so that the resulting rate of return is an after tax figure, set at 
a level comparable to that realized by similar, but unregulated firms. 

(iv) Gas costs — the actual monies paid gas producers (whose prices 
are regulated under the Natural Gas Act) are flowed through into the rates 
paid by the pipelines customers. Unlike oil pipelines, the gas pipelines 
actually takes title to the transported gas. 

These four elements comprise a pipeline's cost of service, which is 
divided by the number of units of through-put to arrive at unit charges 
levied on customers. It should be emphasized that only actual outlays, 



139 

depreciation, and capital costs are charged gas pipelines customers. Any 
overcharge which may result through miscalculation in estimating rates 
or other factors is usually refunded to customers. 

Oil Pipeline Regulation. Oil pipeline regulation has evolved at the 
ICC (this responsibility has been transfered to FERC by the Department 
of Energy Act) under the Hepburn Act and the Court Cases' consent decrees 
in a manner which is rather different from evolution of pipeline • regulations 
at the F.P.C. The elements described below — which are nominally similar 
to the cost factors upon which gas rates are based — are computed in 
a much different manner than what has been described above. 

(i) Operating costs — these are relatively straight forward as with gas. 

(ii) Depreciation — oil pipelines are depreciated based upon initial 
investment, adjusted to reflect the current value of the facility. This 
adjustment is based on the inflation rate of the materials and services 
used in pipeline construction, and brings the current valuation up to ap- 
proximately the pipelines present market values. A fraction of this valuation 
is charged off, as depreciation is with gas pipelines, each year for the cost 
of service computation. 

Unlike gas, oil pipelines apparently are not written off scrap to zero 
or scrap value for rate making purposes. Their valuation, or adjusted net 
investment, is continually maintained and bears little relationship to ori- 
ginal cost less depreciation — the rate base for gas pipeline rate making. 

(iii) Return on investment — under the consent decree, oil pipelines 
owners are theoretically limited to receiving a 8%, and in some cases 10%, 
return on investment, or more correctly valuation, which has been used 



140 

in current practice before the ICC. However, of this 8% or 10%, at least 
during the year in which it is earned, only 7% can be passed through to the 
pipeline project's equity owners. The allowable 7% rate of return on 
valuation contrasts with the ICC practice of allowing the accrual of rates 
1 to 3 percentage points higher than the consent decree permits. Actually, 
higher returns can be earned and either retained or used to finance new 
pipeline investments. It is unclear exactly how much cumulative extra 
revenues have been retained by pipeline equity owners over the years. 

(iv) Interest paid on debt is allowed in the cost of service cal- 
culation. 

In practice, before the ICC up to the transfer of these functions to 
FERC, valuations have been used as the basis for the return computation. 
A rate of return was selected — which need not result in the 7% maximum 
dividend payment of the consent decree — and applied to the valuations 
rate base. 

A pipeline's capitalization, which is based on the original investment, 
is typically 90% debt and 10% equity. The rate of return is applied to 
a valuations rate base, which is generally much larger than the depreciated 
value of the original investment. This results in a highly leveraged situation 
for the equity holders. Consider this purely hypothetical example which 
illustrates the leverage involved: 

A pipeline was built 20 years ago at a cost of $1 million. A sinking 
fund was established for its debt (although even if debt holders have not 
been paid off, interest on the debt is collected and paid thru the tariffs 
charged), where in the depreciation essentially paid off the boundholders , 
leaving the equity investment of $100,000 still intact. The valuation 
of the pipeline has doubled to $2 million due to inflation and 7% of this 



I 



141 

valuation or $140,000 is paid to equity holders yearly. Their return on 
equity is therefore ($140,000 divided by $100,000) 140% per year. Higher 
effective rates of return may result from accrual of rates of return above 
1% (stemming from the 8% or 10% returns built into pipeline rate structures) 
and their retention by pipeline companies or their equity holders. 

This example illustrates how the regulatory format which has been 
used by the ICC can result in a very high percentage return to equity owners. 
These returns, as a practical matter, can be effectively enhanced by use 
of retained surplus earnings to finance new or expanded pipelines. 

Critics to ICC valuation type regulation have asserted that these high 
rates of return — both actually paid out in terms of dividends and not 
directly paid out but realized in terms of free financing for new pipeline 
investments — are tacit subsidies to the pipeline owners (who are also 
users) and discriminate unfairly against non-owner users. These critics 
would hold that gas pipeline type regulation would be a remedy to this 
problem, because it would lower the effective return on investment and 
thus end the subsidy. 

Possible Effects of Pipeline Regulation Transfer to Department of 
Energy (DOE), Now that responsibility for both gas and oil pipelines 
resides in DOE ' s FERC, it appears that a possibility exists that the oil 
pipeline regulatory format may be changed, to parallel gas pipeline reg- 
ulation. The Trans-Alaskan Pipeline System (TAPS) rate case is now before the 
FERC and the rate base computation is one of the most important items in 
contention. This case will doubtless set far reaching precedents as to the 
regulatory format for all oil pipelines. If the gas pipeline approach is 
applied to oil, it could lead to broad rate revision, wherein all oil 
pipelines rates would be re-evaluated in light of new rate base considera- 
tions. This could result in a market lowering of most rates. 



142 

It is conceivable that new net investment values based on original 
investment less depreciation will be computed and a whole new rate of 
return calculation procedure instituted along the lines of gas pipelines. 
This would compensate, through the cost of service calculation, for the 

I 

cost of debt and equity separately. But only debt actually outstanding ' 
would be compensated for, and the rates of return would apply to net, | 
depreciated investment rather than valuation. The overall result of regulating 
oil pipelines under gas pipelines precedures will be to lower rates markedly. 

*/ 

3.1.11.3. The Question of Divestiture 

The controversy surrounding pipeline divestiture focuses on the issue 
of vertical integration and its use by the major petroleum companies as | 
a means of extending and enhancing their market power for anticompetitive 
purposes. In general, the arguments used for and against pipeline divesti- 
ture are similar to those used for and against general vertical divestiture 
of the petroleum industry. Only with respect to the common carrier status 
and natural monopoly characteristics of pipelines are the arguments sig- 
nificantly different. 

Efforts to alter the shipper-owner relationship in the petroleum o 

industry date back at least 70 years. As previously discussed. Congress 

debated but ultimately rejected a proposal to prohibit oil pipelines from 

transporting in interstate commerce any commodity in which they had any 
1/ 

interest . 

^/ Prepared by Howard Useem, Economic Analyst, Economics Division. 

j^/ Congress considered including oil pipelines within the definition of 
a common carrier in the Commodities Clause amendment to the Hepburn 
Act (34. Stat. 585 (1906)). 



143 



Over the past 40 years, bills have been introduced in nearly every 
Congress to prohibit or curb petroleum company ownership of petroleum 
pipelines. Many of these bills have sought to extend the commodity clause 
to oil pipelines, while others luve proposed an outright ban on petro- 
leum company ownership to oil pipelines. None has been enacted. 

The current congressional interest in pipeline divestiture (as well 
as generalized vertical and hoL^ lontal divestiture of the petroleum in- 
dustry) appears to have been tr ;ered mainly by the events surrounding 
the petroleum shortages and massive rise in oil prices which resulted 
from the recent Arab oil embargo. Additional impetus appears to be sup- 
plied by the growing public distrust of big business (e.g., in 1976, five 
of the ten largest domestic corporations were oil companies), belief that 
antitrust suits either take too long (e.g., the Federal Trade Commission's 
still pending 1973 antitrust suit against the eight largest petroleum firms 
and the Department of Justice's still pending 1969 antitrust suit against 
IBM) or that they will never be consumated , and concern over the viability 
of independent petroleum firms and new market entrants who may not have 
direct access to crude petroleum or petroleum products but nevertheless 
play an important competitive role. 

During the '93rd, 94th, and the first session of the 95th Congress 
approximately 150 bills have been introduced concerning some aspect of pipelines 
a significant number of these called for an alteration in the shipper-owner 
relationship. Some have called for full vertical divestiture of the petroleum 
industry which would result in the separation of the production, refining, 
transportation, and marketing segments of integrated firms. Others have 
been less sweeping, with some calling for a prohibition against pipeline 
owners from transporting their own oil . 



144 

The following bills typify pipeline divestiture legislation intro- 
duced in the 93rd Congress: 

* The Petroleum Marketing Divorcement Act (S. 2082) would have 
made it unlawful for any person engaged in the marketing of refined 
petroleum products to engage in production, refining, and transportation. 

* The Free Enterprise in Petroleum Act (S. 3318) would have prohibited 

under the Interstate Commerce Act any common carrier pipeline from 

transporting crude oil or petroleum product if it is owned by the 

pipeline or its affiliates. 
2/ 

* S. 2260 would have fostered pipeline divestiture by prohibiting 
pipelines owned by oil companies from crossing Federal lands. 

The most significant divestiture bill during the 94th Congress was 
the Petroleum Industry Competition Act of 1976 (S. 2387). This bill called 
for full vertical divestiture, splitting the largest firms into three seg- 
ments — production, ref ining-marketing , and pipeline transporation . It 
would have made it unlawful for any major producer, refiner, or marketer 
to own or control a pipeline. This bill would have affected the pipeline 
holdings of all eighteen major petroleum companies and would have required 
an estimated 66 other companies to dispose of some assets. On June 15, 
1977, the Senate Judiciary Committee favorably reported S. 2387 to the 
floor of the Senate; no further action was taken. In addition to this 



2/ Long title: A Bill Relating to the Authority of the Secretary of the 
Interior to Grant Right s-Of-Way for Pipelines under the Mineral Leasing 
Act . 



145 

bill, there were a number of others in the 94th Congress which would also 
have affected the petroleum industry shipper-owner relationship. The Oil 
and Gas Transportation Competition Act (H.R. 4012) would have made it un- 
lawful for any corporation or association to transport by pipeline any 
petroleum or petroleum product which it owned or controlled. The Public 
Energy Act (H.R. 1011) would have made it unlawful for any refiner to ac- 
quire any pipeline asset. The Petroleum Industry Antitrust Act (H.R. 4910) 
would have made unlawful under the Interstate Commerce Act for any pipe- 
line company to transport crude oil or refined product if the commodity 
transported is owned by the pipeline or any of its affiliates. 

During the first session of the 95th Congress, more than 25 bills have 
been introduced concerning petroleum pipelines; as in previous Congresses, 
a significant number of these call for an altered shipper-owner relatipnship . 
The Pipeline Divestiture Act (H.R. 8506) would prohibit petroleum transpor- 
ters from controlling any interest in any production, refining, marketing 
or transportation asset, and would prohibit any person from transporting 
any energy resource or product in which it has any interest by means of any 
transportation asset in which it has any interest. The Oil and Gas Transpor- 
tation Competition Act (H.R. 7402) would amend the Clayton Act to make it 
unlawful for any person who owns or controls a pipeline to transport by 
such pipeline any petroleum, or petroleum product which it owns, controls, 
or has owned, controlled, produced, or refined. The Federal Lease Petroleum 
Transportation Act (H.R. 7412) would amend the Mineral Leasing Act of 1920 



24-786 O - 78 - U 



146 

to prohibit persons controlling petroleum pipelines from transporting 
Federal lease petroleum it owns, controls, or has owned, controlled, re- 
fined, or produced. While this is not an exhaustive listing of all pipe- 
line divestiture bills introduced during the 93rd, 94th and 1st session 
of the 95th Congress, it is indicative of the degree of congressional interest 
in this issue. 

The Issue of Pipeline Divestiture. In order to assess the necessity and 
efficacy of legislating pipeline divestiture, it is necessary to examine 
two elements: one, the degree to which integration into pipelines creates 
competitive problems which can be rectified through legislated divestiture; 
and second, the impact that pipeline divestiture would have on the petroleum 
industry, specifically on its ability to produce, refine, transport, and 
market petroleum and petroleum products, and its impact on the economy in 
general. The following summary enumerates some of the more significant arguments 
for and against pipeline divestiture. However, the validity and relative 
merits of these arguments will not be examined or assessed. 

Arguments for pipeline divestiture. Proponents argue that vertical 
integration can be used to reinforce the horizontal dominance of the major 
petroleum companies. They note that the top twenty companies own 74 percent 
of the Nation's crude oil reserves, control 80 percent of refining capacity, 
and account for 78 percent of refined petroleum product sales. Since they 
have such a high degree of control over each stage of production, they can 
use their vertical integration to shift their market power from one production 
stage to another in order to strike their competitors where they are most 
vulnerable. Integration into pipelines facilitates the use of price squeezes, 



147 



denial of supplies, and foreclosure from markets by the major integrated 

companies as a means to discipline, coerce, and, where necessary, 

eliminate their independent competitors. The principal arguments 

for pipeline divestiture were summarized in a Senate Antitrust Sub- 

3/ 

committee staff study. It stated that: 

Perhaps the most significant control apparatus employed by the 
majors is the crude pipeline system. The majors' control of crude 
gathering lines and trunklines extends their influence over crude 
well beyond their own production. Crude gathering lines are second 
only to lease ownership as a source of crude supply. Numerous in- 
dependent producers must sell their crude to major owned gathering 
systems to have an outlet for their crude. Flexibility in pipeline 
connections, though technologically feasible, is uncommon. The ty- 
pical independent usually faces the choice of selling to a major ga- 
therer or shutting in production. 

The pattern and ownership of the crude trunkline system limits 
access of domestically produced oil to refineries except through the 
integrated companies. Independent production that hasn't fallen in- 
to the majors' hands through a farm-out contract or a gathering line 
sale enters the majors' control at the trunkline terminal. 

Crude trunklines are owned and built almost exclusively by sin- 
gle firms or major-dominated groups of companies. The planning of 
joint venture/undivided interest lines invariably involves the shar- 
ing of information about each partner's intentions and capabilities 
in crude production. Crude trunklines also are an integral part of 
the crude exchange system, a quasi-barter mechanism that restricts 
the availability of much domestic crude to companies with access to 
crude and a crude trunkline. In a crude exchange, two or more com- 
panies agree to make approximately equal amounts of crude available 
to each other at mutually convenient locations. The system re- 
moves a substantial portion of crude from open cash markets and 
forecloses the market to some potential buyers. Moreover, the 
system deters price competition among exchange members who would 
suffer retaliation if they were to injure the interest of an ex- 
change partner. 



3/ U.S. Congress. Senate. Committee on the Judiciary. Subcommittee on 
Antitrust and Monopoly. Vertical Divestiture in the Petroleum Indus- 
try. Staff report prepared by the majority staff (unpublished, no date) 
pp. 9-11. 



148 



The majors' control of crude weighs most heavily on the in- 
dependent refiner seeking raw material for his refinery and the 
potential refining entrant who needs supply guarantees to gain 
financial support for a refining venture. The majors' dominance 
in crude has enabled them to achieve the bulk of refining market 
share, particularly in some regions. It also has relegated some 
independents to subsidiary status. Integrated firms often enter 
processing agreements with independent refiners in which the re- 
finer takes crude from a major, returns finished product, and re- 
ceives a processing fee. The arrangement makes the refiner an ad- 
junct to the major. 

Products leaving the refinery often are as subject to the ma- 
jors' control as crude entering the facility. As in crude, pipe- 
lines are a critical link in the majors' control [of petroleum pro- 
ducts] . Major control of product pipeline shipments gives the do- 
minant firms power to determine the disposition of a large share 
of product. 

Pipeline owners can employ a variety of methods short of di- 
rect refusal to resist the intrusion of non-owner shippers. Min- 
imum tender requirements and the failure to provide terminal faci- 
lities inhibit non-owners' shipments to the point that the outsider 
often finds it more expedient to sell his oil to the pipeline owner. 
Non-integrated pipeline companies, by contrast, aggressively seek 
the business of refiners and marketers. 



Arguments against pipeline divestiture. The arguments against 



pipeline divestiture are, in many ways, more detailed, since they are 
generally stated by those companies who favor the status quo and can 
cite current operating data. Opponents of pipeline divestiture argue 
that vertical integration in general , and vertical integration into 
pipelines in particular, is not per se anticompetitive. They point 
out that economic theory demonstrates that vertical integration 
can be used for predatory purposes only if a horizontal monopoly 
or cartel exists at at least one stage of production. Absent the 
presence of the horizontal monopoly or colusive behavior among 
the integrated firms, it would then be necessary to demonstrate 
that each and every firm at any state of production has commonality 



149 

of interest and therefore identical interests in engaging in predatory 
activities. However, even if these conditions were met, in order 
for the predatory activities to be sustained over a period of time 
there would also have to be barriers to entry of new firms and barriers 
preventing existing independent firms from integrating around their 
competitor's monopoly. Not only is this unsupported by any exist- 
ing data, it is argued, but if such anticompetitive behavior were exhibited 
then it would be subject to attack under the Federal antitrust laws. 

In its analysis of vertical divestiture, the Energy Resources 
Council concluded that there are real cost savings associated with 

vertical integration and that it is not just a ploy for increasing 

4/ 

a company's market power. It stated that: 

Vertical integration is not synonymous with monopoly power. 
Companies may consider vertical integration as one means to ef- 
fect benefits based on reasons such as — 

Direct cost advantages : These are obtained through re- 
ducing inefficiencies and achieving economies inherent 
in large scale operations. 

Input and output flow stability: Backward integration 
insures supplies of raw materials while forward integra- 
gation affords greater sales predictability. 

* Fear of foreclosure: Non-integrated firms may become in- 
tegrated if they feel it provides a possible competitive 
advantage . 

* Complementary uses of existing facilities: Successive pro- 
duction stages can use existing skills, experience, facili- 
ties and/or resources. 



4/ Energy Resources Council. Analysis of Vertical Divestiture, May 1976: 
pp. IV-V. 



150 



Although integration can result in lower costs to consumers, 
which may increase a firm's competitive advantage, integration in 
itself does not confer monopoly power. It takes a conscious deci- 
sion by a firm to abuse its market position; and confirmation of any 
such abuse should be a step prior to changing the industrial stuc- 
ture in which there is potential for such abuse. 

Thus, opponents would contend that pipeline divestiture would eliminate 
those cost savings associated with vertical integration (e.g., reduced 
transactions costs, easier coordination and planning for capital invest- 
ments and security of supply/outlet ) and thereby result in higher tariffs 
and ultimately higher consumer prices. 

It is also noted that nearly all most oil pipelines are common carriers 

1/ 

and therefore subject to Department of Energy carrier regulations. As common 

carriers, their rates are regulated to provide a fair rate of return, and 

they are required to provide equal access to all shippers. The relative absence 

of complaints from non-owners shippers or potential shippers, it is argued, 

implies either that government regulation is effective, or that there are 

few problems between the pipeline owners and independent shippers, or both. 

6/ 

In his testimony before Congress, Chairman George Stafford of the ICC stated: 

Today there are so few complaints and so few problems that I 
must say [the pipelines are] one of the best run transporation 
systems we have. . . . In conclusion, it would appear that ex- 
cept for certain impediments brought about because of environ- 
mental considerations, pipelines have been constructed on an 



5/ In 1973 more than 76% of oil pipeline mileage was interstate (Source: 
American Petroleum Institute); as of 1974 84.5% of all crude and pro- 
duct was shipped through federally regulated pipelines (Source: Inter- 
state Commerce Commission) . 

6/ U.S. Congress. Senate. Committee on Interior and Insular Affairs. Spe- 
cial Subcommittee on Integrated Oil Operations. Market Performance and 
Competition in the Oil Industry. Hearings, 93rd Congress, 1st session, 
1973: p. 896. 



151 

as-needed basis and generally provide good service. It has 
been our experience that pipeline rates are just and reason- 
able. . . .We have received no complaints in recent years in- 
volving allegations relative to the size of tender, the fail- 
ure to publish through routes and joint rates, or to provide 
service to independents. 

By impairing the industry's ability to execute throughput agree- 
ments, it is believed that pipeline divestiture would also seriously 
affect the industry's ability to finance large scale pipelines. Absent 
Federal Government intervention (e.g., guaranteed loans), this would most 
likely result in increased tariffs, increased dependence on foreign 
supplies as new domestic fields are left untapped for want of a 
low cost means of transportation of the crude. 

In general, opponents of pipeline divestiture argue that there is 
little theory or concrete evidence which can be used to demonstrate that 
vertical integration can be, or ever has been, put to anticompetitive 
use; and that only vague unsubstantiated allegations have ever been made 
to such effect. Absent such proof, it is argued, it would be folly to 
embark on a course of action that would entail significant costs without 
any perceived benefits. 

Implementation of Divestiture. The "spin-off" and the sale 

of assets are the two standard techniques used for corporate divestiture. 

The spin-off is accomplished by the establishment of a new corporate 

entity which is given the divested assets and associated liabilities 

7/ 

by the parent corporation. The stockholders of the parent corporation 
are then given pro-rata shares of the new company. However, the 
high degree to which pip'elines are debt financed (it is not uncommon 

7/ Spin-off divestiture was the technique used in the 1911 dissolution 
of the Standard Oil Trust. 



152 

for 90 percent of a pipeline to be debt financed) magnifies the 

problems associated with this type of divestiture. The Department 

of the Treasury noted in its analysis of petroleum industry divestiture 

that "spin-offs, because they dispose of assets without direct return 

of value, reduce the assets and earning power backing for the divesting 

company's outstanding debt [and in this case, the divested company's 

debt]. To the extent that a pipeline would have large amounts of 

unamortized debt not covered by sinking funds, this would be the 

case. Thus lenders who are relying on the company's overall credit-worthiness 

as security for their investment would be adversely affected and 

might litigate or attempt to enforce their rights under existing 

loan agreements which generally place restrictions on the sale 

8/ 

or spin-off of assets." 

On the other hand, divestiture could be implemented through the sale 
of the pipeline assets. The number of firms affected by pipeline divest- 
iture and the amount of assets involved would, of course, depend upon the 
specific legislation, but in the case of S. 2387 (94th Congress) at least 
84 firms would have had to dispose of some pipeline assets: 18 major oil 
companies, 45 other firms having a partial ownership in interstate oil 

pipelines, and 21 additional firms if S. 2387 applied to ownership in in- 

9/ 

trastate oil pipelines. Valued at current market worth, the assets 



8/ Department of the Treasury. Implications of Divestiture. June 1976: 
p. 201. 

9/ American Petroleum Institute. Divestiture Legislation — Companies 

Affected by S. 2387. Unpublished memorandum by Barbara Loveless, September 
27, 1976. 



153 

involved in such a pipeline divestiture would be enormous, in the range of 

$14 billion. While a divestiture of this size is unprecedented, it is not 

10/ 

necessarily unworkable. 

Questions as to the availability of qualified purchasers (i.e., 
large non-petroleum companies with suf f icient*capital ) and the impact 
the sale would have on the stock and financial markets would, of course, 
have to be addressed. Moreover, there would be a problem if qualified pur- 
chasers could not be located, in that the pipeline assets might have to 
be disposed of through a "distress" sale in order to comply with the provisions 
of the legislation. 

Th e cost o f divestiture. For the most part it is difficult to quantify 
all of the potential costs and benefits associated with pipeline divestiture. 
Part of the problem arises from unformational limitations; industry documents 
and data are in general considered proprietary and therefore are made publicly 
available often only when they support the industry's position. More importantly, 
however, is that economic theory and econometric models are able to quantify 
only certain kinds of costs and benefits. For example, while an econometric 
model can quantify the potential impact of a divestiture-induced reduction of 
petroleum industry capital expenditures, it would not be able to directly assess 
the benefits of an increase in competition. Therefore, studies such as those 
discussed below tend to compute potential costs of pipeline divestiture without 
quantifying its potential benefits. However, this is not to say that they are 
fallacious; rather, they are assessing only one particular perspective of the 
issue and when taken in that light they can be instructive. In the end, it 

10/ For example, the Trans Alaska Pipeline System cost about $7.7 billion; 
the SOHIO Pipeline Company has assets of about $1.6 billion. The source 
of the total figures was the Association of Oil Pipelines. 



154 

it will be essentially a polical judgment whether the potential benefits 
of pipeline divestiture outweigh the potential costs. 

Since it is generally recognized that vertical integration confers 
substantial costs savings, dis-integration could therefore reimpose those 
costs without necessarily providing any offsetting cost savings to the 
firm. The precise magnitude of these costs is difficult to quantify, but, 
whatever their size they would either have to be passed on the consumers 
in the form of higher prices and reduced supplies, or have to be absorbed 
by the firms and their stockholders, or both. 

Pipeline divestiture would also significantly affect the ability of 
the divested pipeline companies to raise debt. Since the debt of 
most pipelines companies is generally guaranteed by the full 
faith and credit of the parent organizations who are primarily major 
petroleum companies, they are therefore able to raise large amounts 
of capital without incurring exhorbitant interest rates. Thus, 
without the backing by the major petroleum companies, pipeline companies 
wishing to make new investments, would probably still be able to raise capital, 
but it might cost more to do so. And, increased capital costs results, trans- 
port delivery tariffs would have to be increased in order to maintain the 
same rate of return. 

To the extent that throughput and deficiency agreements can be obtained 
from credit worthy corporations by the pipeline companies following their 
divestiture, the risk premium on capital costs will be appreciably reduced. 

11/ For example, about 85% of the $7.7 billion Trans Alaska Pipeline System 
(TAPS) construction costs were financed at an average interest rate of 
about 9%. TAPS ownership is: Sohio-33.3%, BP-15.8%, ARCO-21.0%, 
Exxon-20.0%, Mobil-5.0%, Union-1.7%, Phillips-1 . 7% , and Amerada Hess-1.5%. 



155 

However, since typical divestiture legislation does not require 
producers to enter into such agreements with the pipelines that 
they previously owned (although some of the proposed divestiture 
legislation may preclude such agreements as a result of its definition 
of "control"), this may be less of an offsetting factor than might 
otherwise be supposed. Furthermore, since pipelines are common carriers 
and therefore required to provide equal access to all shippers at 
non-discriminatory rates, there would be little, incentive for producers 
to enter into such arguments with the pipelines they just divested. 

Perhaps the most potentially significant element of pipeline 
divestiture is its possible impact on the economy. During the transitional 
period (which has been estimated to last easily as long as ten years 
if companies and their debt holders decide to litigate), the capital 
expenditure plans of the industry would be seriously disrupted. 

A recent study by the Congressional Research Service concluded 
that full vertical divestiture (production, refining, transportation, 
and marketing) could at peak increase unemployment between 290,000 
and 700,000 persons, and could cause a decline of real GNP of 

12/ 

between $63 billion and $134 billion over a seven year period. 

A draft report prepared for the Federal Energy Administration estimated 

that full vertical divestiture would "cut cumulative reserve additions 

[of crude oil] by 13,311 million barrels, or about a third below 

the base forecast" through 1989. It would reduce petroleum production 

by as much 13.5 percent (1,464 MB/D) and it would impede natural 

1^2/ Howard Useem, and Douglas Bendt. The Impact of Petroleum Divestiture 
on the U.S. Economy. The Library of Congress, Congressional Re- 
search Service, June 9, 1976: 39 p. 



156 

gas production by as much as 5.5 percent (1,007 BCF/YR) . While 
pipeline divestiture is less sweeping than full vertical divestiture, 
it can be presumed that it would have similar kinds of impacts, although 
reduced in magnitude. 

To the extent that pipeline divestiture would disrupt the industry's 
capital expenditures as envisioned in the CRS report on full vertical 
divestiture, and to the extent that pipeline divestiture would necessitate 
increased rates of return as envisioned in the FEA study of full vertical 
divestiture, pipeline divestiture would have roughly the same impact 
on the economy. In light of the magnitude of these potential impacts, prior 
to legislating pipeline divestiture, it would seem prudent to be sure that an 
anticompetitive situation does in fact exist, that divestiture is the least 
costly method of remedying the problem, and that the benefits of divestiture 
outweigh the costs. 

3.1.11.4. A Concluding Note. Since the 1 880 ' s control over oil pipeline 
has led industry critics to assert t hat their special status as the connect in 
link between producers and refiners and refiners and marketers lends unique 
opportunities to engage in anticompetitive behavior. This has been a focal 
point of legislative interest off and on during this century. 

From 1906 onward, pipelines have fallen under ICC regulation. The 
ice's regulatory format evolved before the development of the elaborate 

13/ Federal Energy Administration. Financial Analysis of Vertical Di- 
vestiture. A report prepared by R. Shriver Associates for the 
Competition Task Force. (Draft.) April 3, 1977: pp.V-9, V-11, V-12. 
Resources Policy Division. 



157 

economic theories of utility regulation which began to be developed 
during the 1930's. In retrospect, oil pipeline regulation developed 
under ICC regulation in an environment which existed prior to the 
evolution of modern utility economics. The regulatory format which ICC 
applied grew in the environment and the result was — and has continued 
to be -- much different than today's utility regulation as exemplified 
by interstate natural gas pipelines, which began to be regulated in 
the late 1930's, when the theory of utility economics had become fairly 
well developed. 

The system which did develop is rather unique, wherein shipper- 
owners transport their own goods as well as those of their competitors. 
Some students of the industry have argued that this situation and its inter- 
action with the ICC regulatory approach has resulted in a condition where 
pipeline-owner shippers receive a tacit subsidy which non-owner shippers 
do not get. They note that this stems from the fact that owners effective 
returns on investment are very high, while non-owners do not benefit from 
these extremely high pipeline ownership profits and are indeed disadvantaged 
by having to pay tariffs which generate these high returns. Countering 
this assertion is the fact that there have been very few complaints to 
the ICC from non-owner shippers about tariffs and access. In part this 
may be due to the value of the service provided, i.e., it is cheaper and 
more reliable than the alternatives. Furthermore, the pipeline tariff is a 
relatively small proportion of the final selling price of the transported 
goods . 

Basically, the anticompetitive nature of the shipper-owner relationship 
is almost being exclusively alleged by persons outside the oil industry, 
rather than by supposedly disadvantaged "independent" oil companies. Divestiture 



158 

has been advanced by those wanting a remedy to whatever disadvantages 

may exist, and pipeline divestiture has been a focal point of much legislative 

activity during the post-embargo period. One goal of divestiture would thus 

be to cause free access to the pipelines for non-owner shippers who compete 

with the more integrated owner-shippers and to avoid the tacit subsidy 

for owner shipper which resulted from high returns on equity under 

the current regulatory format. Another would be to create competitive 

conditions in the oil industry as a whole by bringing competition to 

a critical vertical link, separating transportation from other 

activities . 

As regulatory responsibility has shifted to FERC, which also reg- 
ulates gas pipelines, it is possible that the traditional utility format 
may be applied to oil pipelines. If this happens, shippers will still 
be permitted to own pipelines, but returns on equity would be strictly 
limited to levels which typify normal industrial rates of return. Thus 
subsidies would be eliminated and the reasons for divestiture based on 
pipeline ownership and behavior should disappear. This, however, would 
not necessarily deter proponents of pipeline divestiture who see it as 
a simple and effective way to increase competition throughout the oil 
industry by breaking vertically integrated companies. 



159 

3.1.12. Vulnerability of Oil and Gas Pipelines to Sabotage * / 

Pipelines carry huge quantities of energy in the form of oil and 
gas in continuous operations stretching over thousands of miles. Without 
this continuous movement, the consuming industries and other activities 
would be severely disrupted or curtailed. These pipelines were constructed 
and are operated with almost no regard to their vulnerability to persons 
who might, for whatever reason, desire to interfere with this vital move- 
ment of fuel. They are exposed and all but unguarded at innumerable 
points, and easily accessible even where not exposed over virtually their 
entire routes. Given the rise of violent terrorist activities around the 
globe and the proliferation of knowledge and devices which could be utilized 
for sabotage, this vulnerability of the most important energy transporta- 
tion systems of the Nation threatens the national security. 

3.1.12.1. Background . Any form of energy transportation is vulner- 
able tn some extent to violent sabotage or terrorist action. Railroad 
sabotage, by destruction of key bridges or tracks, has been practiced since 
at least the Civil War. The Bonneville Power Administration contended 
with a series of explosions at electric transmission towers which destroyed 
several and caused a great problem in the Pacific Northwest until a massive 
investigation and manhunt apprehended the alleged perpetrator of the sabot- 
age. Trucks moving energy materials can be hijacked, a particular threat 
in the area of nuclear materials movement, because of the possibility that 
some such materials could be manipulated to yield weapons-grade plutonium 
(see 3.1.5.) . 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 



160 

Although all forms of energy movement are vulnerable to some extent, 
pipelines are perhaps uniquely vulnerable. No other energy transportation 
mode moves so much energy, over such great distances, in a continuous stream 
whose continuity is so critical an aspect nf its importance. 

The natural gas pipeline system includes thousands of miles of large 
diameter pipeline, along which are spaced compressor stations where the 
gas is compressed further up the line. Crude oil and petroleum product 
pipelines similarly feature the pipeline systems and pumping stations, 
where diesel powered pumps give the fluid "a push" further on up the pipe- 
line. Both types of pipelines are generally fully automated and centrally 
cont rolled . 

The 81 class A and B natural gas pipelines were reported by the Fed- 
eral Power Commission in 1975 to have 187,233 miles of transmission line, 
supported by hundreds of compressor stations. This major network of natural 
gas transmission lines are, moreover, interconnected at thousands of points. 
In each instance, for compression and interconnection, as well as frequently 
for river crossings and other purposes, the pipeline systems are partially 
or completely exposed. The rights-of-way are clearly identified both on 
readily available maps and at their locations by signs and cleared areas. 

The 123,000 miles of crude oil and petroleum product trunk transmission 
lines and thousands of pump stations are configured in much the same way as gas 
transmission compressor stations. Similarly, the pipes are often exposed 
and the pumping station facilities are above ground. 

In the instance of the Alyeska pipeline, the 800 mile 48-inch pipe 
which delivers crude oil produced on the northern coast of Alaska to the 
southern coast for transshipment to California or elsewhere in the U.S., 



161 

the pipeline is fully exposed over most of its route, held above the ground 
surface on pylons in order to prevent thawing of the permafrost it traverses. 
Unlike the Alyeska pipeline, most other major natural gas and oil pipelines 
include multiple pipelines using the same right-of-way separated by several 
feet. If this almost uniquely vulnerable trans-Alaskan system were interrupted 
for three weeks, the heated oil would cool to the point that it could 
not be moved, putting the pipeline out of service for six months. Yet, 
despite this possibility, the U.S. will be obtaining almost 10% of its 
petroleum through this line in a few years. There have already been two 
attempts to cause a break in the pipeline. In one case the perpetrators 
used dynamite; in the other, it is not clear what was used. Damage in 
both cases was minor and quickly repaired. 

3.1.12.2. Areas of Vulnerability . A person desiring to disrupt the 
flow of energy to a given region or in the most damaging way to the Nation 
as a whole would obviously focus his efforts on those systems which carried 
the largest amount of energy. Data revealing the natural gas pipeline systems 
relative throughputs is routinely published by the Federal Energy Regulatory 
Agency (successor to the FPC) . Similarly, the Interstate Commerce Commission 
publishes data on oil pipeline throughput, also likely to be contained in 
publication by the FERC as successor to this function of the I.C.C. In 
addition, detailed maps of the systems and facilities are available to the 
public, including one map of petroleum pipelines which is so detailed that 
one inch on the map is equal to 24 miles. 

Filings which are accessible to the public detail the types and confi- 
guration of equipment utilized at key points of the system, equipment 
which is often in full view and easily identified by an onlooker at the 
site. 

24-786 O - 78 - 12 



162 

A single break in line pipe of a gas or oil pipeline system can be relati- 
vely quickly repaired, depending on its extent, but in almost no case would 
require more than a few days. If isolated, the break can be bypassed by 
natural gas flows using the system of interconnections the pipeline com- 
panies maintain, with transfer and displacement of gas supplies. Natural 
gas is fungible throughout the Nation's pipelines, and can be routed to its 
destination over multiple paths in many cases. In addition, if only one 
of several pipes in a right-of-way were damaged, it is possible that the 
remaining pipelines could pick up the slack. 

A break occurring under a river bed, or in similarly located sensitive 
spots, perhaps by the deliberate dragging of an anchor or a heavy device with 
an explosive charge, would present a much repair tougher problem than on land, 
as well as possibly being slower in detection and causing major pollution. 

Pipeline rights-of-way are frequently inspected for leaks and patential 
problems, generally from the air by planes with special leak detection equip- 
ment. But a quick operation, night-time operation, or well-camouflaged 
operation could easily evade detection for long enough to inflict damage. 

Crude oil and product pipelines are not similarly interconnected, 
because the commodities in the lines vary from time to time and liquid 
systems do not have the same characteristics as gaseous systems in dis- 
placement. However, a break in a single line pipe could be perhaps accom- 
modated by the other lines in a given right-of-way. Even if this is not 
possible, the storage of products and crude at points up the pipeline 
might well suffice for the few days of intensive activity required even 
to repair a major break. 

If multiple breaks of a pipeline occurred concurrently as a result of con- 
certed action by a group of people, the problem would be substantially 



163 

exacerbated by the shortage of repair equipment and skilled personnel on 
call to any given pipeline. The arrival of repair experts and the 
necessary equipment from other points of the country, if such multiple 
breaks were concentrated on a given system, would add days to the period 
required before the system was operating again. If multiple pipeline breaks 
occurred on several major systems simultaneously, the availability of pipe- 
line repair experts and equipment, including the spare line pipe, would 
probably require several weeks of effort to effect a general repair. 
If the systems served a given area, such as the Northeast, the possibilities 
of rerouting gas supplies to make up for the closed down systems would also 
be reduced. Gas supplies could be ended for periods of several weeks, 
and liquids supplies drastically curtailed. If such an event occurred 
during the winter, not only would repair be more difficult, but the effects 
of critical gas needs going unmet would be more devastating. 

Such an organized destructive effort would probably require dozens 
of participants and would consequently be more likely to be detected and 
interdicted by the authorities. 

The purpose of a breaking of line pipes along an oil or gas pipeline 
system might be to cause a destructive explosion or conflagration along a 
given point of the right of way. Most pipeline rights-of-way avoid heavily 
populated areas and major industrial areas for this reason, but there are 
exceptions where important facilities or possible targets are within a 
short distance of pipelines. Valves which can cut the flow of gas or 
liquids are spaced periodically along the lines but are also very acces- 
sible. Most are unmanned and exposed and are either remotely operated 



164 

by an automated facility or require a workman to arrive and physically shut o 
the flow. In the former case, the communication link between the valve and 
the control center may be severed, and it is not clear what the status of 
the valve would be in that event . It may close automatically or remain 
open depending on its programmed instructions, but it is probably not likely 
that a pipeline company would risk the entire system shutting down on ac- 
count of a simple valve's malfunctioning remote control communication 
system. In the latter case, valve equipment may be tampered with or the ar- 
riving workman interfered with to prevent a shutdown of the flow. 

In either case, gas or liquids would continue to escape from the 
line until the pressure in the pipeline had dropped to ambient levels for 
whatever segment of the line was contained between valves and only then after 
notice of the event and the closing of the valves. This would certainly 
amount to millions of cubic feet of gas and hundreds of barrels of liquids, 
all highly flammable, and, when mixed to the correct proportion with air, 
explosive. 

Another complete range of possible activities to be considered is 
related not to terrorism or sabotage but to theft and other more standard 
crimes. The technology for tapping into a pipeline, even a high pressure 
natural gas pipeline, without causing a leak, explosion, or other major 
incident revealing the existence of the tap, is published and well-known. 
With throughput measured in hundreds of thousands of barrels per day or 
billions of cubic feet, quantities of fuel missing from pipelines worth 
millions of dollars annually would be difficult to detect. In 1975, the 
FPC reported 140 billion cubic feet of natural gas as unaccounted for, 
about half of which was lost during transmission. This gas, which was 



165 

shown on meters entering the system, but was neither sold to customers, 

placed into storage, or used in compressors, is eventually paid for by 

those customers who do receive gas at meters. Its value, based on the 

average resale value of natural gas by interstate pipelines in 1975, 

was worth $110 million. A portion of it may well have been stolen. 

Despite the serious potential for disruption of service of direct 

damage by breaking or rupture of line pipe along the right-of-way, it 

is more likely that potential saboteurs would focus their efforts at more 

critical points of the systems, segments which would require much more 

time to replace or repair and upon which the overall system depends. Compressor 

or pumping statins are obvious targets, because their loss would reduce 

the flow of gas or liquids along the line, even after the line itself 

was repaired, by requiring the compressor or pumping performed at the 

previous facility to suffice for twice the usual distance along the line. 

When an explosion and fire destroyed pump station number 8 of the Alyeska 

pipeline, the 1.2 million barrels per day of throughput expected from 

the Alyeska system was reduced to .7 million barrels a day. The pump station 

will not be fully operational again until March, 1978, despite an intense 

1/ 

rebuilding effort — nine months after the original accident. The pipeline 

itself was not damaged, but was shut down for ten days as a safety precaution. 
Because all lines in a given right-of-way are usually served by a given 
pump or compressor station, its destruction could not be bypassed without 
routing the liquids or gas through an entirely separate route. 

_1/ Goune, E.P. "Alyeska Speeds Rebuilding of Damaged Pump Station," Oil and 
Gas Journal, Vol. 75, No. 47, Nov. 21, 1977, p. 83. 



166 

If adjacent pump stations were destroyed in a liquid line, depending 
on the particular configuration of the line, the entire flow might be stopped 
for the entire repair period. On a gas line, some gas would flow, but the 
amount would be a fraction of the normal flow. 

Another possible target area might be the junction of rights-of-way 
of two major systems, particularly in the case of natural gas, where an 
interconnection facility would probably be sited. Both systems might be 
disabled and a longer repair period required, even if the interconnection 
was separately repaired after the two systems were back in service. 

Perhaps the most critical point of the largely automated pipeline 
systems would be the "nerve center" or central control depot, at which auto- 
mated equipment keeps track of the commodities in the pipeline and relays 
instructions to remote unmanned equipment as well as to manned pumping and 
compressor stations. Sometimes sited on or near the right-of-way, such 
installations may include a compressor or pump station. If destroyed, 
the operations of the pipelines could be disrupted for a long period 
while repairs are effected. Manual operation of the system using a 
temporary communication system might be feasible, but only if additional 
personnel could be trained in the operation in a very short time. The 
time required for repair or reconstruction of the control center of an 
automated pipeline would require several months at a minimum, an intoler- 
ably long time for customers of the pipeline. 

3.1.12.3. Protective Measures . Little can be done to stop a deter- 
mined, well-equipped, and knowledgeable saboteur or terrorist who desired 
to disrupt a pipeline's operations. It would not be feasible to monitor 
the entire length of a pipeline frequently enough to prevent any action. 



167 



And virtually, no such security precautions were taken in that safer day 
when most of our pipelines were built. 

Nonetheless, the risks of an attempt to knock out the center control 
room or compressors or pumps can be decreased greatly by the use of defensive 
devices such as electrified fences, guard dogs, and guards, forcing a potential 
assaillant to focus his attack at parts of the system that are less well 
defended but more readily repaired. 

A Subcommittee of the Senate Judiciary Committee looked at the special 
problems of protecting the Alyeska pipeline, which was slightly damaged 
by one attempt at sabotage shortly before it was completed. The Sub- 
committee was stunned at the lack of planning and thought given to the 
security of the pipeline before it was built, especially considering that 
terrorism has been a fact of international if not internal affairs for more 
than a decade. 

The Subcommittee recommended the establishment of an Office of Energy 
Security in the Department of Energy. The duties of the Director of the 
Office would be as follows: 

(1) Coordinate, supervise and provide policy direction for the 
regulation and inspection of all personnel, facilities, and de- 
vises related to securing against threats, thefts, terrorist or other 
criminal attacks, and sabotage, the processing, transportation, 

and handling of all oil and gas resources and products; 

(2) Monitor and conduct tests of the facilities and devices des- 
cribed in paragraph (1) as a basis for making recommendations 

to the Congress for improving the security of oil storage facil- 
ities, pumping stations, and pipelines; 

(3) Develop policies and coordinate and supervise relationships 
between the Department and all appropriate Federal, State and 
local governmental agencies and private industry with respect to 
(A) all matters relating to the collection of information neces- 
sary to develop contingency plans to respond to threats, thefts, 
terrorist or other criminal attacks, and sabotage, with respect 
to oil and gas resources and products, (B) the identification and 



168 



prosecution of those who, through criminal means, seek to destroy 
or interfere with the lawful use of our oil and gas resources or 
products; 

(4) Assess the need for and the feasibility of establishing a security 
force or agency within the Office by which to carry out security 
measures in accordance with the intent of the Congress; 

(5) Make recommendations to the pertinent Cabinet officer with 
respect to research needed to enable the Department to carry out its 
security functions. Ij 

Such an office would be able to perform as yet undone tasks of identi- 
fying and coordinating the resources of the industry that could be called 
upon if needed, the repair equipment and personnel. It could alert the 
companies to the threat, urge them to have contingency preparation completed 
and standby equipment and supplies. Advance planning for conceivable 
repair requirements would save valuable days in the event of a need. 
Very importantly, the existence of preparations and security precautions 
would itself be a deterrent to would-be terrorists or saboteurs. 

3.1.12.4. Analysis Pipelines carry vital energy in enormous amounts 
and continuous streams to consumers many of whom have no other readily 
available supply. An obvious target to those who would disrupt the 
society by interrupting its flow of energy, pipelines have nonetheless 
been cosntructed and operated esssentially without precautions against 
such possibilities. 

The risks and penalties of such potential interruptions are great enough 
that at least those precautions which can be taken relatively cheaply should 



IJ U.S. Senate. Committee on the Judiciary. Subcoimnittee to Investigate 
the Administration' of the Internal Security Act and Other Internal 
Security Laws. The Trans-Alaskan Pipeline — Problems Posed by 
the Threat of Sabotage and the Impact on Internal Security. 95th 
Congress, 1st Session, U.S. Govt. Printing Office, Washington, D.C. 
1977. 



169 

be taken, such as contingency planning by the pipelines. A Federal co- 
ordination effort could also be mounted with a small expenditure of time 
and funds. 

The politicization of energy is complete. It has been used as a "weapon" 
internationally by the Arab oil embargo. The TAPLine pipeline from the 
Persian Gulf to the Mediterranean through Syria was shut down by explosions 
and has not been reopened. Although domestic conditions have calmed greatly 
since the height of political alienation and resistance during the Vietnam 
war, when sporadic acts of terrorist violence occurred, such passions could 
be aroused again. The United States is not a favorite of several international 
terrorist groups, who could probably manage to put operatives in position to 
cause trouble if they so chose. 

Criminal motivations might also lead to possibilities of such actions, 

holding entire populated areas hostage for energy. And the vulnerability 

of such systems to nuclear attack is also great, as two studies for the 

3/ 

Defense Civil Preparedness agency have shown. 

The best way to prevent such events is to deter them by making the 
most devastating of them more difficult to accomplish, and the unprevent- 
able incidents less damaging by a swift repair capability. To continue 
to ignore the possibility of such incidents is to make them more likely. 

As one witness before the Senate Subcommittee put it: "If for some 
reason, tanker movements of oil to our eastern refineries were shut off to 
the extent that we would have to depend on our domestic supply of oil and 

_3/ The Department of Interior, Office of Oil and Gas; Vulnerability of 
Total Petroleum System, by Maynard M. Stephens; Washington, D.C. 1973. 

Vulnerability of Natural Gas Systems, by Maynard M. Stephens. 

Washington, D.C. 1974. 



170 

natural gas moved by pipelines, concerted sabotage by a group of less than 

50 people could render the northeast portions of the country virtually 
'±.1 

without fuel." 

The threat is thus quite clear. That any action, even the basic 
coordination and planning for such contingencies, has begun to respond 
to the threat, is not clear. 



171 

3.1.13. A National Power Grid * / 

Issue Definition. The concept of a national power grid is based on 
the present trend toward more intercompany and interregional electrical 
transmission connections reaching the stage where virtually all of the 
Nation's electric power systems are operated as a single entity. The 
goals of a national power grid would be to use electricity more ef- 
ficiently and to increase the reliability of electrical power systems so 
that for example, blackouts such as those that occurred in the North- 
east in 1965 and in New York City in 1977 could be avoided. 

Three factors contributing to a power system's efficiency and reliability 
are its interconnection, wheeling and pooling capabilities with other power 
systems. Interconnections are the linkages of two electric systems permit- 
ting the transfer of electricity in either direction. Such an arrangement 
allows optimal use of the systems existing generating capacity, provides back- 
up in shortages to prevent blackouts, and can in some cases eliminate the 
need to build additional generating capacity. Wheeling is the use of one 
utility's transmission facilities to move electricity between two other 
utilities which are not interconnected. Publicly-owned utilities favor such 
arrangements, while private utility companies fear that they would be forced 
to subsidize their public counterparts if ordered to provide wheeling lines. 
Pooling is the interconnection of more than two electric utility systems 
to provide for the most efficient use of their collective resources and 
facilities . 

*/ Prepared by Gary J. Pagliano, Analyst, Environment and Natural 
Resources Policy Division. 



172 

Some electric utilities are committed to greater interconnection, 
wheeling and pooling, but some experts allege that efficiency and reliability 
problems would still exist. The 95th Congress has examined the Federal 
role in the power efficiency and reliability issue and has acted to expand 
the role of the Federal Energy Regulatory Commission (FERC) in helping 
to resolve the issue. However, advocates of a national power grid and 
its goals believe that Congress did not go far enough, and that Congress 
will again have to address the issue of further expanding the Federal 
role in a national power grid context in order to achieve greater efficiency 
and reliability in distributing U.S. electrical power. 

3.1.13.1. Background . On November 10, 1965, a massive power black- 
out took place in New York, New England and parts of Canada. Shortly 
thereafter, the Federal Power Commission (FPC), predecessor of FERC, re- 
ported that cascading power failures, like the Northeast blackout, were 
usually the result of insufficient capability within the transmission links 
of a system or group of systems to withstand the sudden demands placed upon 
them. The report recommended greater interconnection and coordination of 
Northeast power systems to help prevent similar occurrences. 

To avoid cascading power failures in Western Europe, electrical 
utilities have used large, tightly interconnected power grids as standard 
engineering practice. In England and Sweden, national grids tie all power 
plants together. All the plants of France, West Germany, Belgium, and the 
Netherlands are tied into an international grid. 

After the Northeast blackout of 1965, electrical utilities responded 
to demands for increased interconnections by forming regional coordination 



173 

areas into National Electric Reliability Councils. Many utilities have 
long had informal power pools to exchange power when it was to their 
mutual economic benefit to do so, but these pools were smaller than the 
proposed utilities' regional coordinating areas. After 1965, electrical 
utilities interconnected transmission lines not only among the traditional 
members of the economy pools, but also among interregional members to 
strengthen their backup for unusually high demand or for emergencies. This 
process led to increased interconnection among some of the National Electric 
Reliability Councils. 

3.1.13.2. Present and Future Interconnections . At the present time, 
seven of the nine National Electric Reliability Councils are somewhat inter- 
connected and have the ability to move large quantities of power from one 
area to another. The seven councils are (1) East Central Area Reliability 
Council (ECAR), (2) Mid-Atlantic Area Council (MAAC), (3) Mid-American Inter- 
pool Network (MAIN), (4) Mid-Continent Area Reliability Coordination Agreement 
(MARCA), (5) Northeast Power Coordination Council (NPCC), (6) Southeastern 
Electric Reliability Council (SERC), and (7) Southeast Power Pool (SSP). 
The Electric Reliability Council of Texas (ERCOT) and the Western Systems 
Coordinating Council (WSCC) each operate independently of other U.S. coun- 
cils, but have substantial interconnections with Mexico. Three councils, 
the NPCC, MARCA, and WSCC include Canadian interconnections which are 
especially opportune because the winter-peaking Canadian utilities provide 
important seasonal diversity interchange with summer-peaking utilities 
in the U.S. 



174 



i i 



3 S 

i § 



s i 



3 * 



□ 'A 




175 

A Congressional Research Service study entitled National Power Grid 
System Study — An Overview of Economics, Regulatory, and Engineering Aspects, 
reports electrical utilities around the country are planning additions to 
the present systems of interregional interconnections (see map). The 
end result should be stronger ties among the already interconnected regions 
by 1985, but WSCC and ERCOT will remain essentially isolated from the 
rest of the nation. 

Some studies have examined the potential benefits of interconnecting 
the Western U.S. (essentially the WSCC region) with the Central and Eastern 
U.S. interconnection systems. One of the most recent studies, the Report 
of the Western United States: Central United States Study of Transmission 
Interconnection, concluded that constructing interconnection facilities 
to provide reliable operation was not economically feasible. The Congres- 
sional Research Service Power Grid Study added that major transmission 
lines connecting the eastern and western systems could be justified only if 
very large power plants were constructed near the coal-rich areas of the West. 

The situation of ERCOT is somewhat different. ERCOT has several low- 
voltage ties with other regicins which are operated normally open but can be 
closed in an emergency to furnish some protection in the immediate vicinity 
of the ties. Generally these ties are inadequate for parallel operation 
of the ERCOT and neighboring systems. In 1972 the FPC' s regional office 
in Texas did a study which concluded interconnection of ERCOT and SPP 
would enable ERCOT to reduce its reserves over the period from 1975 through 
1980 achieving a net savings of $156 million at 1972 price levels. 
ERCOT' s response to the FPC study was that interconnection of the two regions 



176 

would be detrimental from both service reliability and economic standpoints. 
The FPC could not take action because ERCOT had only intrastate intercon- 
nections and thus, was not subject to the FPC's jurisdiction. 

3.1.13.3. Interconnecting Aut hori ty . The FPC's primary authority 
promoting electrical power reliability is restricted to creating regional 
districts for voluntary utility interconnections and coordinating various 
electrical facilities involved in interstate commerce (16 U.S.C. 824). 
There are exceptions to this rule. First the FPC could order intercon- 
nections on its own initiative if emergency conditions existed such as 
war and emergency power shortages (as provided by 16 U.S.S. 824a). Second, 
if a utility or a State commission files an application with the FPC 
to make an interconnection, the FPC can review the application and then 
order the interconnection if it is found to be in the public's interest. 
But it should be emphasized that the actual decision to interconnect must 
be initiated by the utility or the State Commission. 

The 95th Congress is looking to expand FERC's (FPC) interconnection 
authority in interstate power distribution. The pending National Energy 
Act (NEA) allows FERC on its own motion to order the interconnection of 
two utilities, provided such action would be in the public interest as 
well as satisfy one of three tests: that overall conservation of energy 
or capital would be encouraged, that the efficient use of facilities and 
resources would be optimized or that the reliability of one or more in the 
involved systems would be improved without impairing the reliability on 
other systems . 



177 

In addition, the NEA gives FERC for the first time some jurisdiction 
in the wheeling and pooling of electric power. Under the NEA, FERC is 
allowed to issue a wheeling order upon the application of a utility. To 
satisfy claims that wheeling orders might damage existing competitive 
relationships, FERC will have to conclude competition would not be hurt 
before proceeding with a wheeling order. NEA also requires FERC to study 
the potential benefits of pooling arrangements and allows FERC, to recom- 
mend utilities voluntarily enter into pooling agreements. 

In sum, the Congress has expanded the Federal role in interstate electri- 
city distribution to assure increased efficiency and reliability of regional 
power systems. However, the Congress has done so with caution avoiding 
any major changes in the current system of how utilites actually allocate 
their electricity. As efficiency and reliability become more of a regional 
and national consideration, the trend will be toward a more nationally 
oriented power grid system. As a result, some believe Congress in the 
future will again have to address the Federal role in such a power grid 
system specifically on two important issues: first, the wheeling of power 
among utilities, and second, creating a central authority with vested 
rights to have the final word on regional or national power distribution 
in the U.S. 

3.1.13.4. A Central Authority and Wheeling . Presently, regulation of 
the electric utility industry is diffuse because local, State and Federal 
governments all have jurisdi cation in some aspect of the industry particular- 
ly electric transmission. FERC by virtue of the Federal Power Act has 

24-786 O - 78 - 13 



178 

jurisdiction over sales of interstate power which accounts for about 15 per- 
cent of all power sold in the U.S. The Tennessee Valley Authority which is 
run by local and regional interests accounts for 5 percent and Federal hydro- 
electric power projects such as Bonneville account for another 5 percent. 
But the bulk of U.S. power, 75 percent, is transmitted intrastate and as 
a result is under the jurisdiction of the State public utility commissions. 

While the power efficiency and reliability issue has elevated the coordina- 
tion of power systems to a regional and national level, but the main 
jurisdictional authority has remained at the State level. The National 
Electric Reliability Councils are national in scope, but have no real 
authority to implement policy. FERC will probably have its authority 
expanded through the NEA, but it will only include mandating interconnections 
on the interstate market. FERC's authority is restricted on wheeling power 
which is essential to integrating power system with adjoining systems. 
For example, if there are three utilities interconnected, and the utility 
in the middle does not want to wheel power while the other two utilities 
want to exchange power, then the exchange does not take place. 

Some argue that a central authority is necessary for local power systems 
to be properly integrated into large regional or national grids which would 
distribute power efficiently and reliably. This central authority would 
monitor the energy situation in every part of the region or the country and 
could dispatch power from the central point when the situation called 
for it. This central authority would make the final decision on allocation 
of power in its jurisdictional area. 



r 



i 



179 

Three alternatives for organizing such a central authority could be 
an interstate compact arrangement, a much stronger FERC, or a corporation 
with vested rights to operate a national power grid. Under the interstate 
compact alternative, the Federal Government would delegate authority through 
interstate compacts allowing States to establish larger planning and reg- 
ulatory organizations for distributing electrical power. This alternative 
would be a cooperative venture between States and the Federal Governemnt 
involving some expansion of Federal involvement in State and regional 
affairs, but not an overwhelming involvement. The main advantage of this 
arrangement is that: (1) it would be easy to implement since the State 
regulatory apparatus is already in place, and (2) it would utilize the 
extensive regulatory experience that States have built up over the years. 
The main disadvantage is that the Federal Government would give up authority 
to make decisions affecting State actions. 

A stronger FERC authority would give the Federal Government more say 
in allocating power. President Carter in his National Energy Plan favored 
this approach. As a result, the Plan proposed amending the Federal Power 
Act to enable FERC to require interconnections between utilities even if 
they are not presently under FERC jurisdiction. FERC would also be 
authorized to require wheeling the transmission of power between two 
noncontiguous utilities across another utility's system. The advantages 
would be that (1) it would increase the benefits of load diversity — by 
permitting bulk power suppliers to wheel power from coast to coast when 
peak demands in the North are lower and high in the South, and vice-versa, 
and (2) it would facilitate wheeling power from power-surplus areas into 
power-short areas. The disadvantage is that there could be States' rights 
problems . 



180 

The third alternative involves creating a national power grid by con- 
veying title to all existing transmission lines to a new corporate entity 
and vesting this new entity with authority over planning new transmission 
lines interconnecting base-load generating plants and local centers through- 
out the nation. This new entity would operate as a third-party common 
carrier with its operations and rates regulated by FERC. Ownership of the 
new entity could be 100 percent Federal Government, 100 percent private, 
or jointly owned by the Government and private investors. The advantages 
as with a stronger FERC would be in the diversity and wheeling. Similarly, 
the disadvantage could be in the area of States' rights. 

3.1.13.5. Conclusion . The concept of a national grid is based on the 
present trend toward more intercompany and interregional electrical trans- 
mission connections reaching the stage where virtually all of the Nation's 
electric power systems are operated as a single entity. While some electric 
utilities are committed to greater interconnection, wheeling, and pooling, 
some experts allege that efficiency and reliability problems still exist in 
the industry. 

The 95th Congress has examined the Federal role in the power efficiency 
and reliability issue and has acted to expand the role of the Federal Energy 
Regulatory Commission. The pending National Energy Act allows FERC on its 
own motion to order the interconnection of two utilities, provided such 
action would be in the public interest. In addition, the NEA gives FERC 
for the first time some jurisdiction in the wheeling and pooling of electric 
power. Under the NEA, FERC is allowed to issue a wheeling order upon the 



181 

application of a utility. FERC is also required to study the potential 
benefits of pooling arrangements and allows FERC to recommend utilities 
voluntary enter into pooling agreements. 

The Congress has agreed upon legislation that avoids major changes in 
the current system of how utilities actually locate thqir electricity. But 
as the efficiency and reliability of power systems become more of a national 
consideration, the trend will be toward a more nationally oriented power 
grid system and could cause a reexamination of the Federal role . As a 
result, some believe Congress in the future will again have to address the 
Federal role in such a power grid system particularly in two issues areas: 
first, the wheeling of power among utilities, and second, creating a central 
authority which would have the final decision on regional or national 
distribution in the U.S. 



182 

3.1.14. Conversion of Florida Natural Gas Line to Petroleum Products 
Transportation . */ 

The Florida Gas Transmission Company (FGTC) applied for permission 

in 1974 to abandon natural gas service in a 24-inch pipeline and to 

convert the facility to carry petroleum products which are currently moved 

by water transport. The delivery of these products by pipeline would 

speed delivery, reduce the amount of energy consumed in transportation, 

and lower costs. The FGTC would augment the system with new pump stations, 

lateral lines, terminals, and new facilities to accomodate the carriage 

and distribution of the new cargo. But there are opponents to the conversion 

and regulatory approval must be obtained. 

3.1.14.1. Background . There are two natural gas pipelines that currently 
deliver natural gas from Texas and Louisiana to Florida. The original 
line is 24 inches in diameter and is looped with a 30-inch line for a 
combined capacity of 725 million cubic feet per day (mmcfd). When existing 
natural gas contracts expire in July 1979, only enough gas (625 mmcfd) 
will be available to justify the* operation of one pipeline. New construction 
would be needed for only 50 miles of the 900-mile line for it to carry 
all of the available gas. This would leave the 24-inch line surplus. 

If the conversion were approved, the initial planned flow of petroleum 
products through the proposed line would be 200,000 barrels per day (b/d), 
eventually reaching a full capacity of 350,000 b/d. At 200,000 b/d the 
line could carry 76 million barrels per year, the equivalent of 75.7% of all 
the petroleum. products carried by vessel in that trade in 1973. At 350,000 b/d 
the products line could carry 128 million barrels of light petroleum each year. 

_*/ Prepared by David Lindahl , Analyst, Environment and Natural Resources Folic 
Division, CRS . 



183 

That figure would exceed the 1973 total for all such products carried by 
coastal vessels in that trade. 

3.1.14.2. Consumer Benefits . The FGTC claims that Florida consumers 
will benefit from lower transportation costs for petroleum products because 
of the inherent advantages of pipelines over other modes of transportation. 
The FGTC estimates that the initial cost of transportation of petroleum products 
through the converted line will be approximately the same or slightly 
less than for tanker transport but, once the conversion and development 
capital is invested into the line, costs are expected to rise more slowly 
than for tanker transport. In addition, there are substantial environmental 
benefits of pipeline transport over tankers, including greater safety, 
the absence of risk of marine oil spills, the shorter transit time, and 
the unlikelihood of strikes that would prevent delivery of vitally needed 
fuels and other petroleum products. 

Although this conversion will not reduce the amount of gas avail- 
able in Florida, several gas-burning municipalities have objected be- 
cause it would reduce the opportunity for delivery of future supplies of 
gas if they should become available, even if there is no immediate pros- 
pect for such supplies. If more gas did become available in the future, 
a new pipeline could be built to deliver it to the Florida distribution 
system. In the meantime, Florida consumers would have the benefit of an 
inexpensive and reliable means of delivering petroleum products, and gas 
consumers would not have to bear the expense of maintaining an idle gas 
line . 



184 



3.1.14.3. Maritime Opposition . The independently-owned U.S. -flag 
tanker industry and the seafarers' unions oppose the proposal on several 
grounds. The industry has had periods of depression in recent years and 
fears that conversion of the pipeline, as proposed by the Florida Gas 
Transmission Company, would lead to a diversion of petroleum product cargoes 
away from the U.S. -flag tankers and tank barges. In particular, the industry 
is concerned that this would further increase unemplojmient in the merchant 
marine in terms of numbers of ships and jobs for American workers. 

In 1973, 56.7 million barrels of petroleum products were transported 
by tanker vessel from Texas ports to ports in western and eastern Florida 
(Table 1). 



Table I. Tanker Transport of Petroleum Products 



TO EAST COAST FLORIDA PORTS (1973) 



Jacksonville 
Port Canaveral 
Port Everglades 
Miami 



17,320,218 barrels 

752,521 barrels 

18,246,935 barrels 

34,227 barrels 



TO WEST COAST FLORIDA PORTS (1973) 



Tampa 

St .Petersburg 
Pensacola 
Key West 
Port St. Joe 



18,912,846 barrels 

152,378 barrels 

195,051 barrels 

331,110 barrels 

770,176 barrels 



56,715,462 barrels 



Source: Office of Domestic Shipping, Maritime Adminstration , U.S. 
Department of Commerce, 1973. 



185 

An additional 43.7 million barrels were carried into Florida ports 
from Texas by U.S. -flag tank barges (Table II). 

Table II. Barge Transport of Petroleum Products 
TO EAST COAST FLORIDA PORTS (1973) 



Jacksonville 1,684,930 barrels 

Port Canaveral 28,289 barrels 

Port Everglades 21,516,421 barrels 

Miami 704,302 barrels 



TO WEST COAST FLORIDA PORTS (1973) 

Tampa 18,244,754 barrels 

St .Petersburg 155,317 barrels 



43,731,870 barrels 



Source: Office of Domestic Shipping, Maritime Administration, U.S. Depart- 
ment of Commerce, 1973. 



The combined tanker and barge carriage of petroleum products (primarily 
gasoline) into Florida ports from Texas, therefore, totalled 56.7 million 
barrels in 1973. 

The industry claims that, based on the 1973 figures, tanker vessels and 
tank barges would have carried only 24.6 million barrels if the pipeline 
had been operating at its initial capacity during that year. It is con- 
ceivable that even if the demand for light petroleum products from Gulf 
Coast refineries continues to increase in Florida, as it is certain to do, 
the products pipeline flowing at full capacity could transport all that 



186 

is needed at lower cost for the foreseeable future, thereby eliminating 

1/ 

U.S. -flag tankers and barges from the trade. 

The shipping industry claims that diversion of 80 to 100 million 
barrels of petroleum products each year from the U.S. -flag tanker and tank 
barge fleets would have disastrous affects of the merchant marine and on 
the U.S. economy. The industry predicts that because tankers are forced 
to spend almost all of their time in coastal domestic trade, removal of a 
substantial portion of that trade would leave these vessels with no alter- 
native to going into lay-up. This prediction was made, however, before 
the need developed for such ships to move surplus Alaskan oil from 
the West Coast through the Panama Canal to Gulf and Eastern ports. 
Until a transcontinental pipeline is built to relieve that traffic, 
these ships will probably be in great demand whenever they are avail- 
able. Completion of a west-to-east pipeline, however, would probably 
once again release a large number of Jones Act tankers that would be 
affected by the loss of the Florida trade. 

The Marine Engineers Beneficial Association estimated that the 
full-time equivalent of between 8 and 13 tankers (each carrying a 
crew of 38-40) and 24 barges (each carrying a crew of 6 or more) 
might be lost as a result of the conversion of the products pipe- 
line. The industry is concerned that, even beyond the revenue lost 
to vessel owners, an increase in the supply of tankers well in excess 

]_/ Herbert Brand, The' Transportation Institute, testimony before the 
Federal Power Commission, Docket 74-192, June 9, 1975. 



187 

of the available supply of cargoes will provide little incentive for any 

carrier to increase its capital investment in U.S. -flag vessels. The 

consequences of this would be a drastic decline in shipbuilding orders 

and a lack of work in U.S. shipyards. 

More than 50 percent of the tonnage of merchant vessels delivered 

by U.S. yards between 1970 and 1974 was built in response to orders for 

vessels qualified for the coastal trade. It is estimated that between 

1975 and 1980, the Jones Act will generate a need for another $1.3 billion 

2/ 

in construction, and between 1980 and 1985 an additional $1.7 billion. 
The industry claims that because some of the vessels are nearing the end 
of their useful lives, the American shipbuilding industry would greatly 
benefit from orders to build new and more modern replacements. The 
shipping industry fears, however, that this rejuvenation of the fleet 
will not take place if the proposed products pipeline is completed. 

The tanker industry further claims that the conversion of this pipe- 
line and the diversion of cargoes from U.S. ships would force their sub- 
sequent lay-up and would adversely affect the merchant marine's national 
security role in reducing the growth of the fleet and by leaving it un- 
prepared to respond in a crisis. A major advantage that domestic tankers 
have over a pipeline in such a situation is their routing flexibility. 
A pipeline cannot be rerouted in order to obtain petroleum products from 
alternate supply sources or to deliver them to other destinations. The 
industry claims that forcing U.S. ships into lay-up where they may be sold 
for scrap and shutting down U.S. shipyard capacity would greatly reduce that 
response flexibility. 



2/ Ibid. 



188 

3.1.14.4. Proceedings . The issue will be resolved by a decision 
of the Federal Energy Regulatory Commission (FERC), probably by mid-'1978. 
A FERC administrative law judge has already made an initial recommendation 
that it would be in the public interest to convert the line, and the transfer 
price and disposition of proceeds are currently being reviewed by the 
FERC. The Florida Gas Transmission Company hopes to have approval in 
time for a prompt conversion when existing gas contracts expire in July 
1979 and the 24-inch line becomes surplus. 



189 

3.1.15. - Disruption of Energy Transportation by Weather and Natural 
Disasters */ 

Movements of several fuels by several modes of transport are vulner- 
able to significant disruption by weather patterns. The winter heating 
season of 1976-77 provided several excellent examples of such disruption. 
The Ohio River froze bank to bank blocking barge traffic in both fuel oil 
and coal. Coal froze solidly in rail cars, sometimes requiring blasting 
to remove it. Winter snows impeded truck movements of heating oils, gaso- 
line, and LPG. Even gas pipelines, impervious to weather on the surface, 
are subject to limitations of capacity if the demand for heating fuel 
exceeds designed demand ceilings. Natural events and weather can thus 
have significant impacts on the ability of transportation systems to sup- 
ply the fuel required for the United States. The heart of the solution 
is preparedness and prevention. 

3.1.15.1. Background . A large portion of the fuel movement that takes 
place in the United States is vulnerable to disruption from inclement 
weather, and all forms of fuel shipment are subject to disruption by 
natural disasters. Adequate planning for such contingencies can help to 
prevent severe problems, and quick ability to move from one mode of trans- 
port to another in the face of a given situation can also keep fuel move- 
ments going. 

During the winter of 1976-77, abnormally cold temperatures for long 
periods of time, coupled with severe snow and icing, caused problems affecting 
the movement of oil products, LPG, coal, tested the delivery ability of 
natural gas pipelines to carry that fuel, and brought down electric utility 
lines . 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division 



190 

3.1.15.2. Petroleum Products . Many communities in the Ohio river 
valley obtain shipments of oil products from barge tows pushed up the 
Mississippi and Ohio Rivers. Heavy fuel oils are too viscous to be pipelined, 
and such fuel oils throughout the Midwest are most cheaply transported 

by barges to depots from which they can be trucked to the industries and 
utilities which use them. In addition, some quantities of lighter oil 
and gasoline are also barged up the river, perhaps by companies without 
controlled pipeline capacity in the region. 

Last winter the freeze of the Ohio River halted the fuel oil traffic 
for weeks. Stocks ran low and spot shortages occurred. 

Meanwhile, truck deliveries to users of all descriptions were being 
impeded and slowed by the weather even as the usage rate went up to combat 
the cold. Workers fighting the weather to deliver fuels found valves fro- 
zen and trucks hard to start. 

LPG presented special problems, because the market for LPG is largely 
rural and scattered, requiring trucks to negotiate more miles of more 
poorly cleared and maintained roads to deliver the fuel. Extra propane 
trucks were sought across the Nation not only to aid in such deliveries, 
but also to supplement the inadequate LPG pipeline capacity in making the 
long hauls from producing fields. Every available LPG rail car was pur- 
chased or leased. Yet some LPG could not be bought to markets crying for 
them because of rail car shortages. 

3.1.15.3. Coal. The coal movement situation was aptly summarized 
in an article appearing in Coal Week at the height of the winter crisis, 
January 24, 1977: 



191 



Barge traffic is confined to the Tennessee, the lower Mis- 
sissippi and the Tombigbee/Black Warrior systems. For the 
first time in 30 years, the Ohio is said to be shut-in "bank- 
to-bank." Bargemen see the effects of the freeze lingering for 
weeks. "You get a melt going," says one, "and you've got a whole 
new set of problems to contend with." 

Hopes for an extended shipping season of the Great Lakes 
have been dashed by an ice cover, reportedly of over 85%, from 
Duluth through the Saint Lawrence. The only known movement 
of coal on the lakes is a short haul between Toledo and 
Detroit being kept open by Ford Motor. 

Rail movements of coal are bogged down because product is 
frozen into hoppers and can't be unloaded. The problem is 
particularly bad at the major east coast exporting docks. 

The Chessie system is in "a helluva mess," says one insider 
who predicts rail problems for "at least two months." While 
Newport News is operating, Curtis Bay in Baltimore is "nearly 
shutdown." The Norfolk & Western is reported moving product 
"at about half speed" through their Hampton Roads facility. 
Cold also is thwarting ship loadings in Philadelphia. J_/ 

Fortunately, the river thaw came relatively early and was gradual 
enough to prevent f loading and the additional problems that would bring. 

Coal movement on the Northern Mississippi and the Great Lakes must 
contend with severe icing on a regular basis each year, and this obstacle 
to year-round service is perhaps an important reason that such traffic 
is not greater. Users of coal who depend on Ohio river shipments and who 
maintain stockpiles sufficient for only a few weeks may be reassessing 
the necessary cushion of supply in light of last winter freeze. 

Water carriers are, by and large, those most subject to weather condi- 
tions — freezing, flooding, and drought can all have very disruptive impacts. 
In fact, a severe flood may disable a crucical lock or dam, fill in a channel, 



1/ Coal Week , McGraw Hill, N.Y., Jan. 24, 1977, p. 10 "Frost belongs on 
pumpkings , not in the U.S. coal fields. 



192 

clog a key passage with snags and debris, or alter the navigation route enough 
that new charting is required;, any of these can prove an obstacle to water- 
ways shipment after the flood itself has passed. Drought may lower the river 
level enough that the standard towboat and barges used on that river cannot 
be used without further dredging, and shallower draft vessels would probably 
not be available in sufficient quantity. More vessels would be required than 
would normally be used if shallow draft vessels substituted for the deeper- 
draft vessels and the same traffic level was to be maintained. 

Coal movement by railroad is mostly affected by cold weather in the 
freezing of the coal in hopper cars. Wetted down at the mine face in order 
to control dust which could present health problems to miners, the coal can 
freeze into solid blocks inside the hopper cars. Thawing sheds are used in 
some places, but add time to the turn-around time for unit trains. In 
numerous instances last winter, dynamite was used to literally blast the 
coal loose in the cars, which can damage the cars. Alternatives might be 
drying of the coal before loading in the cars, or use of other dust control 
technologies during winter shipping periods. 

Coal slurry lines in water short areas, to the extent they depend on 
surface water for their throughputs, will be very vulnerable to drought, 
because their priorities of use may be relatively low. If the supply of 
water to a coal slurry line was interrupted, moreover, and the line forced 
to be shut down, real problems might be caused by the coal settling out 
of the water medium and perhaps plugging the line at low points. It 
might be necessary to drain the pipeline within a short period of time 
after the water supply was discontinued, presenting problems of disposal 
of the slurry, or to flush and fill it with pure water. 



193 

3.1.15.4. Natural Gas . The natural gas industry must contend with 
cold weather, hoping that the demand for gas caused by heating does not 

exceed the throughput capacity and compression of the pipelines and distribution 

mains. Actual interruptions of a significant portion of natural gas service 

can be caused, however, by hurricanes which force producing platforms 

in the Gulf of Mexico and coastal areas of the Gulf to be shut in and 

deserted until the storm passes. If a late season hurricane in the Gulf 

coincided with an early cold snap in the consuming region of natural gas, 

problems might result. In any case, storage filling operations, depended 

upon more each year for peak load cushions of gas, are affected. If gas 

is found in the Atlantic OCS, such storms may cause similar interruptions, 

and early planning of OCS pipelines and platforms, as well as onshore 

storage and temporary cut-off capability, would be fruitful. 

3.1.15.5. Electricity . Electric lines can be brought down by high 
winds and icing, although transmission tower designs are predicated on 
extremes of both and few major outages result. Lighting, however, is 
another matter. The New York power outage of 1977 was apparently caused 
by three separate lightning strikes to transmission towers within a 
short period. 

The Southweastern U.S. is the most vulnerable area of the Nation to 
thunderstorms and their accompanying lightning, as is shown by Figure I. 

Remote pumping stations and compressor stations on pipeline are also 
sometimes vulnerable to lightning, but their much lower profile reduces 
the risks by a great amount. 

24-786 O - 78 - 14 



194 



Figure I 




RESCREEN & SQOARE HALFTONES 



195 

3.1.15.6. Earthquakes . Earthquakes are the major form of natural 
disaster other than climate and weather which can affect energy transportation. 
Pipelines, the least vulnerable mode to the latter events, are perhaps 
the most vulnerable to earthquakes, powerful shearing forces along a seismic 
fault can crack, crush, split, or bre.3k the strongest steel pipeline. 

The most vulnerable area is perhaps California, with major gas trans- 
mission lines running through earthquake prone areas near Bakersfield and 
San Francisco, as well as both oil and gas pipelines in the Los Angeles 
area, where the recent earthquake caused fires and service outages. Other 
vulnerable areas are in Washington State, southeastern Missouri, and Alaska. 
N<5 pipeline in the continental U.S. has been built with the earthquake pre- 
cautions of the Alyeska pipelines in Alaska, although some are in as much 
danger. Such areas as St Louis, Missouri; Lima, Ohio; Salt Lake City, Utah; 
and Socorro, New Mexico have both major pipeline installations and a history 
of significant earthquake activity. 

3.1.15.7 Analysis . Obviously little can be done to prevent such 
natural occurrence as this section describes. Actions are limited to develt-tping 
protective measures for facilities and alternate supplies for users. Lo- 
gistical planning for such events should be part of all projects which are 
vulnerable, but would normally be performed without governmental requirements. 
Considerations of the possible occurrences of such events are often part of 
the environmental impact assessments required for facilities and projects 
with a major Federal role. In addition, a Federal relief capability for 
disasters which did not include planning for emergency fuel and power 
supplies would be incomplete. 



196 

3.1.16. Eastern Coal Slurry Pipelines */ 

The coal slurry pipelines proposed currently would all connect west- 
ern coal deposits to markets. Huge eastern coal deposits exist, however, 
and the application of the slurry technology to their transportation 
and marketing may be an early possibility because of several factors and 
possible advantages, if right of way problems are resolved. 

3.1.16.1. Background . The Nation's first operating coal slurry 
pipeline ran from Cadiz, Ohio to the Cleveland area. Built in 1957, it 
operated six years before lowered rail rates and the first use of rail- 
road unit trains drove it from business. Another coal slurry line, planned 
to run to Detroit from Kentucky was never built because rail rates were 
lowered. (See reference in 3.4.4.) The recent renewal of interest 
in coal slurry pipelines, however, has focussed on development of western 
coal reserves, and transportation of them to the market. The issue of 
slurry pipelines and western coal is dealt with in 3.4.6. as part of 
the discussion of the development of that new energy supply region. Slurry 
pipelines may, however, despite the current lack of interest, play a 
significant role in the further development of the massive eastern coal 
reserves. This is a current supply area which has had stagnant production 
over the past several decades, but which is being looked to for substantial 
volumetric growth as well as expansion of market areas. 

Although such developments are, at this point, highly conjectural, 
there are numerous possible factors and advantages of the development of 
coal pipelining in the eastern U.S. that can be cited. 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 



197 

3.1.16.2. Pipeline Availability . First, it is quite likely that 
existing pipeline capacity could be successfully converted from other pur- 
poses and adapted to coal slurry. Major natural gas transmission lines cross 
the Pennsylvania-West Virginia coal regions, some of which are running 
at less than capacity due to the natural gas shortage. 

There is little prospect that supplies of natural gas from the Gulf 
Coast supply area will improve, regardless of pricing policy, to the point 
that major increases in deliveries by these pipelines can occur. In addition, 
substantial imports of LNG ( see 3.3.8), or LPG (see 3.3.9.) on the 
East Coast would offset the need for pipeline supplies brought up from 
the Gulf, especially if the cost of Gulf region production is increased 
substantially by production from such sources as deep gas (below 15,000 
feet), geopressurized brine deposits, or imports from Mexico (see 3.5.14.). 
Alaskan gas supplies will also be expensive and will join these pipeline 
systems obliquely, close to their delivery points. Finally, any major 
natural gas discoveries on the Atlantic OCS, where exploration is just 
beginning, would further reduce the need for long-distance transmission 
of natural gas from the Southwest. 

Because the major pipeline systems have multiple pipes — in some cases 
as many as seven pipelines in parallel — it is conceivable that one or 
more such pipes could be abandoned, converted to carry coal slurry, and 
operated in the opposite direction. They could perhaps deliver eastern coal 
to southeastern or Gulf Coast utilities forced to convert from gas or 
oil to coal in their generators, as well as to new industrial coal-capable 
users . 



198 

Other pipeline systems exist which could carry Pennsylvania coal east 
to New York and Philadelphia or west to Detroit and Chicago. Similarly, 
the major coal reserves of Illinois, a State which has more reserves even 
than Montana or Alaska, lie astride pipeline systems which currently 
carry oil and gas from Texas, Oklahoma, Kansas, and Louisiana, and could 
perhaps carry coal in the other direction. 

Given the probable demand and supply of gas and oil in these regions, 
it appears that spare pipeline capacity may be available for such purposes. 
There is some question about the technical problem of conversion, especially 
the greater abrasiveness of coal slurry than oil or gas and the likelihood 
of wear on the inside of the pipeline. The abrupt turns and rises and falls 
of some gas pipelines may need to be graduated if they are to be success- 
fully converted. But pipeline conversions from gases to liquids and vice 
versa have occurred through the last several decades, and reversals of 
direction also. Two current examples are dealt with in 3.2.1.3. and 3.1.14., 
referring to the Sohio-El Paso reversal proposal and the Florida gas proposal 
When the Cadiz line was inspected after its years of operation, markedly 
little abrasion was found inside the pipeline, and the Black Mesa line 
operating currently in Arizona reportedly is also wearing so well that 
abrasion is difficult to observe. High quality high-tensile strength steel 
is used for major oil and gas transmission systems, and could presumably 
be adapted to coal slurry; compressors and gas valves would obviously 
have to be changed to pumps and liquid valves, and other changes would 
be required . 

The advantages of using existing pipelines are financial. The major 
part of a pipeline system's initial costs are the costs of line pipe and 



199 

installation, costs which have risen enormously in the last few years. Con- 
version of an existing pipeline would cost a fraction of the investment 
required for a new line. To utilize an existing pipeline would not only 
save the coal slurry operation a major portion of the investment other- 
wise required, lowering coal transportation costs, but also would probably 
lead to a reduction of the natural gas transportation costs of those gas 
users still receiving gas from the system, because the pipeline would be 
taken out of the gas utility rate base. 

The diameters of such pipeline systems are more than adequate for 
a major slurry projects, ranging up to 42". , and probably averaging 25". 

Even if existing pipeline capacity cannot be used, it is likely that 
new slurry pipelines will be economic in many parts of the East. Florida 
Gas Transmission is planning a possible pipeline from Kentucky to Florida, 
all new construction. Numerous possible coal consumers have expressed 
interest in purchasing from the line. 

The Office of Technology Assessment's Report on Coal Slurry Pipelines 
chose a hypothetical Tennessee to Florida coal movement as one of four 
pipeline possibilities to be assessed. This route was found to be some- 
what cheaper than unit trains and assumed entirely new construction. 

3.1.16.3. Terrain, Siting, and Sulfur Treatment. One advantage 
which would possibly be of importance is the fact that most eastern coal 
fields are situated in an area of substantial elevation. Transporters 
could essentially pipe coal slurry downhill, greatly reducing the mechanical 
requirement for pumping. 

Another possible advantage, if the coal is to be used for gasification, 
is the siting flexibility that might be provided for the gasification 



200 

plant. Coal and water could possibly be brought to a plant and synthetic 
natural gas taken from it in the same pipeline. 

One of the restraints on the development of eastern coals has been 
the relatively high sulfur content by weight* of such coals. Sulfur occurs 
both in compound and in pyritic form — the later type can often be sub- 
stantially reduced by coal washing. Presumably preparation of the coal 
for slurry could include steps to remove much of the natural sulfur in 
the coal. It is conceivable that additional research may determine ways 
of removing sulfur in transit as a slurry by the addition of sulfur-seeking 
substances to the slurry mixture which could work while the slurry is carried. 
Given its generally higher Btu content, it is possible that when delivered 
such treated eastern coal slurry could be equivalent for the purpose of 
air quality to western coal. 

3.1.16.4. Water . The major problems encountered by western coal 
slurry projects are the lack of readily available water for the carrying 
medium, and the lack of rights-of-way or the power of eminent domain 
to obtain rights-of-way. Water is much more abundant in the East than 
the West, and could be pumped from either surface or ground water sources 
to slurry lines at a small cost relative to some of the proposals for 
western pipeliiies. 

In fact, depending on the destination, water shipped through a slurry 
pipeline might have an economic value of its own. It could definitely, 
when clarified, serve as cooling water for electric utilities and, if treated 
to the proper degree, could be used for industrial processes, steam, 
or even agriculture. Unless a very dilute slurry was used, with more 
water in the mix than the standard one part water to one part coal by 



201 

weight, additional water on site would have to be provided for most coal 
boiler fuel applications or coal conversion processes. However, further dil- 
uting the slurry mixture would increase coal drying problems and change 
pipeline economics. 

3.1.16.5. Rights-of-Way . The right-of-way question which has stymied 
coal slurry pipeline development in the West, would, unlike the water problem, 
also be an obstacle for the eastern coal slurry lines. The slurry technology 
was proved in the 19th century, and railroads have not been unaware of 
it. Although the war emergency pipeline rights-of-way, and many of those 
prior to that period, did not specify the commodity to be carried, since 
World War II most right-of-way agreements by pipeline crossing railroads 
have specified the commodities which could be carried, and have excluded 
coal because of the railroad's own interest in that traffic. An attempt 
by one major pipeline company to build a coal slurry line in the 1960's 
from Pennsylvania to New York foundered on the company's inability to 
obtain new railroads crossing rights-of-way or to obtain favorable court 
decisions to reinterpret or revise the original agreements. It was during 
the post-war period that most major gas and petroleum pipelines now in 
operation were constructed. The legal departments of most railroads, 
aware that railroads had only recently lost their dominance of long haul 
petroleum- product movement, were apparently prescient enough to guard 
against further competition by careful drafting of such right-of-way agreements. 

Land owners other than railroads may actually prefer coal slurry to 
oil or natural gas if a pipeline conversion is sought, because coal slurry 
is non-combustible, while the other fuels have occasionally figured in 
pipeline accidents, explosions, fires, and property damage. 



202 

Congress should thus be aware, when considering a Federal eminent 
domain statute for slurry pipelines, that its passage would be likely to 
create a significant opportunity and movement towards slurry proposals 
in the East as well as the West. 

3.1.16.6. Rail Competition . The financial good health of western 
railroads may have tempered congressional concern about charges that such 
railroads would suffer from slurry pipeline competition. Western coal 
production growth and markets may be able to support both a healthy railroad 
industry moving coal and several slurry pipelines. 

In the East, however, where the railroads have a much weaker financial ^ 
stance and a lower level of maintenance and upkeep, slurry pipeline competition, 
especially with the great economic advantages of cheap water and existing 
pipeline investments, could take much of the bulk movements of coal that might 
otherwise help to sustain shaky railroad systems. 

On the other hand, the health of eastern railroads, particularly the 
Conrail lines, may be so bad that they could be unable to meet the demand 
for coal transportation with or without slurry pipeline competition. The 
limited capital of bankrupt lines may not be invested in requirements for 
coal traffic to the point that track in coal producing areas can be up- 
graded for unit trains and equipment can be added, to provide adequate 
coal hauling service. (See 3.1.7.) Slurry pipelines may be the only way 
for eastern coal production to reach markets in quantities growing as 
fast as is expected or desired. 

It is clear that the competitive situation of eastern railroads is 
weaker than western railroads, even as the economics of slurry pipelines 
in the East may be better than those in the West. Legislation that might 



203 

produce a balanced transportation network of both rails and pipelines west 
of the Mississippi, might lead to the collapse of eastern railroads at the 
feet of highly economic slurry systems in the East. But the eastern rail- 
roads may already be too weak to provide a viable alternative if massive 
increases of eastern coal production are planned. 

3.1.16.7. Barge Competition . Eastern coal slurry pipelines would 
also face barge competition for coal movement, but only along the river 
corridors where barges can be operated. Most existing pipelines do not par- 
allel river points, so if an existing pipeline system is to be used, barge 
competition is likely to be limited. Moreover, barges are more vulnerable 

to river freezing and other weather-related disruptions, and may soon 
experience a significant shift in their economics with the imposition 
of a waterways user charge (see 3.1.15 and 3.1.9). Slurry pipelines are 
probably more economic for bulk long distance hauls; waterways shipments 
are generally much shorter. For a major movement of Appalachian coal to 
Gulf Coast consumers, it is clear that barge tows down the Mississippi 
would offer pipelines tougher competition than unit trains, but would 
not have any major advantage over pipelines. Again, because of geography, 
barges could not compete with most possible pipeline routes. 

3.1.16.8. Conclusion . In conclusion, the factors suggesting that 
coal slurry pipelines could prove economic as a mode of transportation 
eastern as well as western coal appear to be persuasive: the possible avail- 
ability of existing high-quality large-diameter pipelines which may be 
surplus to other needs; the economic advantage both to the coal slurry 
enterprise and to the gas or oil operation of conversion of such excess 
capacity; the ready availability of high-quality and inexpensive water; 



204 

the relative weakness of railroad coal transportation competition; the 
geographic limitations and possible new economic constraints on barged 
coal transportation competition; and the stated desire of the Federal 
Government and projected major markets for rapid growth of eastern coal 
production, among other factors. 

The key determinant of whether such apparent advantages are tested 
in practice will be the resolution of the question of eminent domain, 
so that new pipelines can be built across railroads, or existing pipe- 
lines can overcome existing right-of-way agreements restricting the com- 
modities carried to exclude coal. If the obstacle posed by the rail- 
roads current power to deny pipeline crossings is removed, one can ex- 
pect numerous eastern coal slurry projects. 

One very important consideration to be made by Congress, however, 
in considering whether or not to grant eminent domain nationally, would 
be the importance of the eastern railroads and their vulnerability to 
such competition. Another, from the converse side, is whether adequate 
development and transportation on eastern coal can occur without coal 
slurry pipelines, because of the condition of those eastern railroads. 



205 



3.2. ISSUES AND PROBLEMS RELATED TO ENERGY FROM ALASKA 



207 



3.2.1. Disposition of West Coast Oil Surplus of Alaska Crude Oil. * / 

3.2.1.1. Issue Definition . Now that Alaskan oil has begun to 
flow from the North Slope through the Trans Alaskan Pipeline, a surplus 
of crude oil is likely to develop on the West Coast of the United States. 
The size and duration of the surplus are uncertain, but both appear 

to be great enough to require some means of redistributing the excess 
oil. There is considerable interest in transporting this oil to other 
regions of the country that are dependent either on oil imports or on 
declining domestic fields. The surplus and the market for it, therefore, 
are virtually certain, but the choice of route and means of transport 
have together become one of the most controversial energy transportation 
issues of modern times. 

The following options are discussed in this section: PACTEX Pipe- 
line, Northern Tier Pipeline, Kitimat Pipeline, Trans Mountain Pipeline, 
Four Corners Pipeline, direct delivery by tanker, movement by tank-car 
unit trains, exchanges and exports, and shutting-in North Slope production. 

3.2.1.2. Background and Policy Analysis. The Trans-Alaskan Pipeline 
began operation on June 20, 1977, and the flow soon reached 700,000 
barrels per day (b/d), with 600,000 b/d being marketed on the West Coast 
at a price of about $13.35 per barrel, 40 cents less than Arabian light 
crude oil. This is expected to rise to 1.2 million b/d by early 1978, 
and to stay at that level until increased oil production on the North 
Slope warrants an increase (up to the line capacity of 2.0 million b/d). 
Because of existing production in Alaska and California and because 

of the inabilit y of some California and Washington refineries 

V Prepared by David M. Lindahl, Analyst, Environment and Natural 
Resources Policy Division. 



208 

to process the relatively high-sulfur crude oil from the North Slope, 
West Coast supply now exceeds West Coast demand by 100,000-150,000 b/d. 
By the Spring of 1978, when the pipeline reaches its planned operational 
capacity of 1.2 million b/d. the surplus will probably increase to 500,000 b/d 
Even more importantly, this surplus is expected to grow rather than 
to decline, at least through the late 1970s and into the early 1980s, 
as new offshore production in California and Alaska becomes available 
and as commercial production from Naval Petroleum Reserve No. 1 at Elk 
Hills is marketed. By 1982, the surplus could be as large as 900,000 b/d 
or as low as 550,000 b/d, but it probably will average near the upper 
end of the range (Table 1). Operation of the pipeline at full design 
capacity, however , could add as much as 800,000 b/d to the surplus. That, 
plus additional production from other West Coast areas, could push the 
surplus as high as 2 million b/d by 1985, although it will more likely 
be closer to one million b/d. 

The size of the surplus may be affected to a a large extent by the 
price of North Slope crude oil landed at West Coast terminals. If the 
price of Alaskan oil is several dollars per barrel less than the landed 
price of imports, West Coast refiners will have financial incentive to 
rebuild their refineries to handle its lower gravity and the higher sulfur 
content. They would almost certainly prefer it to higher-priced imported 
crude oil if the differential were large enough to allow rapid amortization 
of refinery conversion costs. If the price is the same as that for imports 
or very near it, the West Coast market for North Slope Crude oil may be 
relatively small and may result in maximum surpluses. The Alaskan oil could 
be marketed only on the West Coast for approximately $2.00 per barrel less 
than the imports on the basis of reduced transportation costs. 



209 



TABLE I . 



ESTIMATED WEST COAST SURPLUS OR DEFICIT OF CRUDE OIL 
(Thousands of barrels per day) 



RESPONDENT 1977 1978 1979 1980 1981 1982 1983 1984 1985 



Federal Energy Admin.: 

Questionnaire 600 900-1,000 ~ 700-1,300 

Study: 

FEA conclusion 600 900-1,000 700-1,300 

Exxon submission 552 697 1,797 

AD Little "Best" 

submission 689 805-1,395 

California Standard 

submission 600 600 

Atlantic Richfield 

submission 300-400 500-600 850 

Federal Power Commission: 

(from Sohio data) 300-600 750-900 

Atlantic Richfield: 



guess" 


400 


400 


400 


400 


550 


600 


650 


700 


case 


400 


400 


400 


500 


700 


1,100 


1,500 


2 ,000 


case 


200 











-200 


-400 


-500 


-700 


200 


600 


500 


700 


600 


600 


800 


900 


1,000 


-815 


-199 


68 


359 


523 


638 


553 


518 


434 



Exxon 
Ashland 

Sohio 300-600 600-800 



Source: Summary of Responses to Joint Committee Questionnaire on Potential 
Problems Associated with the Delivery of Crude Oil from Alaska's 
North Slope, Prepared by the Congressional Research Service for 
the Senate Committee on Commerce and Interior and Insular Affairs, 
U.S. Government Printing Office: Wash., D.C. 1976, p. 16. 



24-786 - 78 - 15 



210 

Additional discounts could be offered for even less if the surpluses were 
to exceed the capacity of existing distribution systems. High entitlement 
values for Alaskan oil could also act as a conversion incentive. In any 
case, the amount of "sour (high-sulfur), heavy" Alaskan oil that can 
be accommodated on the West Cost will be limited by the amount of "sweet" 
(low-sulfur) and "light" crude available for mixing in order to provide 
the necessary range of petroleum products. 

In anticipation of a surplus, several proposals have been made to 
transport the excess oil to areas where the need for it may soon be 
critical. An area that desperately needs the oil, however, the Northern 
Tier of states (Montana, North Dakota, South Dakota, Wyoming, Minnesota, 
and Wisconsin), which will receive by order of the Canadian Government 
reduced amounts of Canadian light oil exports each year until they are 
stopped altogether by the end of 1981. Even though these refineries 
at present have a limited ability to refine higher sulfur oil, a large 
part of the surplus (300,000 b/d) could be used there and even more 
could be handled with modifications to refineries. The problem of the 
Northern Tier refiners is a separate issue and should not be considered 
the same as the issue of surplus Alaskan oil, but the two issues do 
overlap, and if refining and transportation can be overcome, they may 
be mutually offsetting. Even if the Northern Tier does not directly 
receive Alaska oil, it could displace domestic or foreign oil that could 
then be sent to the Northern Tier refiners. At the very least, Alaskan 
oil will "back out," to the extent that it can be marketed, an equal 
amount of foreign oil on the West, Gulf, and Mid-Atlantic Coasts. 

Industry has shown a willingness to commit large amounts of capital 
to these proposals, although those commitments cannot be considered 



211 

open-ended, because the price obtained from the refiner will have to be 
high enough to provide a profit to the producing company after State 
royalties and substantial transportation costs are subtracted. Most of 
the proposals take into account, to the maximum extent possible, existing 
crude oil distribution patterns, and they would consequently minimize 
disruptions as well as costs. The most efficient and least expensive 
proposals would involve transshipment of the Alaskan oil to the West 
Coast, where it would be moved eastward through a combination of new 
and existing pipelines. Some of the existing pipelines would be reversed 
in direction of flow. Other plans include shipment by tanker to the 
Gulf Coast, unit-train transport to the Midwest, and exchanges of surplus 
crude oil with foreign countries. All but the latter would require the 
construction of marine terminals in British Columbia, Washington, California, 
Texas, or Louisiana. 

3.2.1.3. PACTEX Pipeline (Sohio-El Paso). This alternative, as originally 
proposed by Standard Oil of Ohio (Sohio), would require construction of 
a new tanker terminal in the Port of Long Beach, California, which would 
receive 700,000 b/d of oil from Valdez in at least 14 tankers of the 80,000- 
165,000 dead-weight-ton class. A minimum of 200,000 b/d would be diverted 
for use in Los Angeles area refineries, and the remaining 500,000 or more 
barrels would be sent eastward. The terminal would be connected to an existing 
800-mile natural gas line owned by El Paso Natural Gas (approximately 675 
miles) and Southern California Gas Co (approximately 125 miles). The line 
would be modified to carry crude oil and its present direction of flow would 
be reversed. After construction of 227 miles of new 42-inch line, it would 
carry Alaskan crude oil 1027 miles to Midland, Texas, where it would enter 



212 

the crude oil distribution system that emanates from West Texas (Fig. 1). 
This route would not serve the Northern Tier refiners directly but would 
supply crude oil to the Gulf Coast, Midwest, and Great Lakes refining 
regions where most of the domestic refining capacity is located. The 
availability of Alaskan oil, however, could free previously committed 
domestic sources of crude oil for use by the Northern Tier refiners. 
In addition, the Williams Pipeline System has already been expanded 
to move Alaskan crude (delivered by tanker through the Panama Canal) 
from the terminal at: Midland to Tulsa, Oklahoma, and through Mason City, 
Iowa to the refineries in near St. Paul, Minnesota. This alternative 
may eventually include a tanker terminal at Port Angeles (similar to 
that proposed by the Northern Tier Pipeline Co.), a pipeline to the 
refineries around Puget Sound, plus a pipeline to the refineries in 
Billings, Montana. It may also be possible in this proposal to send 
direct tanker supplies of Alaskan oil to Canadian refineries in Western 
Canada in exchange for Canadian supplies sent to Montana and North Dakota, 
although that prospect seems unlikely in the absence of Canadian support. 

PACTEX is actually two separate construction projects that would be 
joined together to supply Alaskan crude oil to Midwestern refineries. 
PACTEX would require the conversion and reversal of the El Paso Natural 
Gas Pipeline and construction of expanded lines to connect the West 
Central Region with the Great Lakes Region. The PACTEX alternative would 
take advantage of the existing excess capacity in the El Paso and Southern 
California gas systems. As a result, it would require considerably less 
new construction than either the Kitimat or Northern Tier Pipelines. 
Additional lines could be converted to provide greater capacity for 
crude oil if natural gas supplies continue to decline. 



213 




















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214 

The PACTEX proposal has a major advantage over the other alternatives 
in that adequate long-term throughput for the line is assured because 
Sohio (as part of British Petroleum), the major sponsor of PACTEX, ovms 
over half of the Alaska North Slope reserves and a share of the Trans- 
Alaskan Pipeline that will carry to it Valdez for transshipment. 

Between one and two years would probably be required to complete 
PACTEX once clearances are received on nearly 700 permits needed from 
Federal, State and local governments. Construction contracts could be 
awarded within a month of the approval of the permits. More of the two-year 
period would be needed for construction of the marine terminal facilities 
at Long Beach than for the pipeline itself. The required capital investment 
is estimated by Sohio to be about $500 million, including port and terminal 
facilities, rights of way, and interest. The cost of transporting the 
oil from Valdez to Midland is said to be $1.55 per barrel. The line 
would accommodate 500,000 b/d at full capacity and additional capacity 
would be built if needed. Financing for PACTEX does not appear to be 
a problem for the sponsor, but large debts resulting from cost overruns 
on the Alaska pipeline could make Sohio financing more difficult than 
expected. Few companies other than Exxon have offered to participate 
in the project, although others with similar interest in transporting 
crude oil from the West Coast to the Midwest as early and as cheaply 
as possible may yet express interest if other alternatives appear less 
favorable economically. Most of the other companies that own North Slope 
crude oil have adequate or near-adequate refining capacity on the West 
Coast and are therefore not as concerned with the problem of redistribution. 



215 

PACTEX could be completed by late 1979, if certification were approved 
and construction of harbor facilities at Long Beach and on the 42-inch 
line between Long Beach and Moreno were begun by early 1978. Sohio 
and El Paso have applied for all three of the major permits that are re- 
quired for completion of PACTEX. Each permit, however, has a different 
timetable. The Bureau of Land Management completed the extensive final 
environmental impact statement, required by the National Environmental 
Policy Act and financed by the PACTEX sponsors, in March, 1977. The Port 
of Long Beach-State Public Utilities Commission draft environmental impact 
report, as required by the California Environmental Quality Act, has also 
been completed. In May, 1977, a Federal Power Commission Administrative 
law judge recommended abandonment of the 30-inch El Paso natural 
gas line. Once it is converted to carry crude oil, PACTEX would come 
under the jurisdiction of the Interstate Commerce Commission. 

Less environmental disturbance is likely to result from construction 
of the PACTEX/Williams combination than from any of the other pipeline 
proposals. New construction would be required for 237 miles of the 
line, and 18 new pumping stations and 160 miles of new transmission lines 
would be needed. Tanker traffic in Long Beach and Los Angeles harbors 
would probably increase about 5%. The projected completion date could be one 
to two years earlier as well, but the project has also be delayed because 
of environmental problems. The sponsors have encountered opposition from the 
South Coast (Los Angeles) Air Quality Management District (SCAQMD), the Environ- 
mental Protection Agency and the California Air Resources Board (CARB), which 
claim that terminal operations and vapor leaks from nine million barrels of 
temporary tank storage would add substantial hydrocarbon emissions to the 
already polluted air. EPA has said that emissions of the type that would 



216 

type that would occur from the venting of escaping volatile fractions 
in the stored crude oil cannot be allowed to increase. Sohio claims 
that the type of tankers and tanks that it plans to operate will not 
add to the air pollution, but until recently CARB and EPA remained un- 
convinced and stalled the project. Sohio has agreed with the Air Quality 
Management District to reduce by 20% the daily pollution of other local 
facilities (such as Southern California Edison power-generating plants). 
This could cost as much as $90 million. CARB has insisted at one point 4 
that Sohio arrange with other facilities to reduce these levels by twice I 
the amount of pollutants that the Sohio operation would emit on the 
worst day of each month, but since modified this requirement. Sohio 
offered to scale down the size of the terminal by eliminating one of 
the three berths. 

The reduction of the size of the facility from three berths (700,000 
b/d) to two berths (500,000 b/d) required supplement to the final environ- 
mental impact report has been approved by the California Public Utilities 
Commission and the Long Beach Board of Harbor Commissioners. If the 
SCAQMD decides in favor of the project as expected, it is also likely 
that CARB and EPA will also give their final approval in early 1978. 

PACTEX has been the subject of great controversy and media attention 
in California. The resolution of this issue is not likely until all of the 
relevant environmental studies and consultant reports have been completed 
and reviewed. The controversy has added greatly to the uncertainty surrounding 
the proposal and may well eliminate the inherent advantage of early implementation 
that it offers over the other proposals. 



217 

The dilennna of the State of California over PACTEX is compounded by 
P.L. 94-258, which requires the Navy to have a 350,000 b/d crude oil transport 
tion system completed by April, 1979, (three years from the date of enact- 
ment of the. Naval Petroleum Reserves Production Act of 1976). The environ- 
mental impacts within the State would be minimized by having the Navy 
construct its pipeline to connect with PACTEX, if permitted. Unfortunately, 
the Navy must make its decision relatively soon, probably before the 
PACTEX controversy is resolved. Because of this uncertainty and under the 
pressure of the legal deadline, the Navy may select the alternative route 
from Elk Hills (NPR 1) and Buena Vista (NPR 2) to a marine terminal at Port 
Hueneme , near Oxnard , California. This could entail even greater negative 
environmental effects in terras of both air quality and vessel traffic. 

The issue is further clouded by concern over future availability of 
capacity to transport new natural gas supplies into California if they 
should become available from Alaska. Phase I abandonment of 500,000 b/d 
capacity, as originally requested by El Paso in order to permit conversion 
of the line for oil transportation, would probably not limit this capacity 
under most supply scenarios. The State's future access to natural gas 
transportation could be reduced substantially, however, under a Phase II 
abandonment (over 500,000 b/d). A Phase II abandonment would probably 
be requested eventually if surpluses prove as large as many have predicted. 
A Phase II application would require a separate Federal Energy Regulatory 
Commission proceeding, and it could be granted in spite of California's 
objections. The Phase I abandonment has been recommended and the FERC 
decision is now pending. 

The current certified capacity of the El Paso system is 3.8 billion 
cfd (cubic feet/day) with a throughput of 2.8 billion cfd. Abandonment for 



218 



Pactex would eliminate 670 million cfd of capacity but would leave a system 
total of 3.13 billion cfd. Gas from Mexico would not likely exceed 300 
million cfd, an amount that would be easily handled by the remaining El Paso 
Gas line. Additional throughput could be accommodated through increased com- 
pression in the line. Ideally, this issue should be resolved after the 
decision is made on the transportation of Alaskan gas, because a shortage 
of gas transmission capacity could occur if California were to receive 
Alaskan gas by displacement through the El Paso/Trans-Western systems. 

As the Energy Resources Conservation and Development Commission has 
1/ 

observed: 

If the FPC abandonment decision is deferred until after 
the resolution of the Alaskan gas issue, debate on this point 
could be closed. Alternatively, if the national administration 
could make an ironclad commitment to the construction of a 
"western leg" gas delivery system if a land pipeline route is 
selected for Alaskan gas transportation, the State's resistance 
on this point would probably end, since the "displacement" re- 
quirement would be removed. 

... The decisions appear to be in precisely the wrong sequence: 
California and the Nation would benefit if the Alaskan gas decision 
could be made first, then the decision on SOHIO [PACTEX]; and, 
lastly, the decision on how to move the Navy's Elk Hills pro- 
duction. The adjustments in timing, by a few months, would offer 
great benefits at very little cost. 

Because of the continuing uncertainties surrounding the project 
Exxon decided in June, 1977, to withdraw from the project. As one of 
the four major oil companies having a stake in the redistribution of 
surplus Alaskan oil, Exxon had held a 20% participation in the pre- 
construction phase of the project. Exxon has indicated that it feels 
a pipeline linking the West Coast with the Southwest and the Midwest 



\l Personal communication to William Van Ness, Chief Counsel, Senate 
Committee on Interior and Insular Affairs, September 14, 1976. 

2/ Wall Street Journal, New York, June 21, 1977. 



219 

is needed to provide a reliable crude-oil distribution system and that 
if "reasonable conditions" could be secured, it would consider rejoining 
the project. 

3.2.1.4. Northern-Tier-Pipeline 

The proposed Northern Tier Pipeline (NTP) would require the construc- 
tion of a tanker terminal and oil storage site at Port Angeles on the 
Strait of Juan de Fuca near the entrance to Puget Sound. That site was 
chosen, because it would not be affected by a Washington State law, now 
being challenged in the courts, which prohibits tankers larger than 
125,000 deadweight tons (dwt) from entering Puget Sound. The Port Angeles 
site has water depth adequate to accommodate tankers of up to 300,000 dwt. 

The tankers from Valdez, Alaska, would unload their North Slope 
oil at Port Angeles for transport to Clearbrook, Minnesota, 1,550 miles 
distant (Fig. II). The 40 to 42-inch pipeline would cross Washington, 
Idaho, Montana, North Dakota, and Minnesota and would connect with ex- 
isting lines along the way to serve refineries in the Rocky Mountain and 
Mid-Central States. At Clearbrook, connections with the Lakehead and Min- 
nesota pipelines would extend the oil distribution to the Upper Mid- 
west and the refining center near the* Great Lakes. 

The design capacity of the NTP would be 1.3 million b/d between 
Port Angeles and North Bend, Washington, where provisions would be made 
to supply 500,000 b/d to the Puget Sound refiners in case they decided 
to lay a connecting pipeline. The capacity from North Bend to Clearbrook 
would be 700,000 b/d initially and would later be increased to 940,000 
b/d. The estimated cost of the line, including port work, is approximately 
$1.2 billion. Estimated costs of delivering each barrel of oil from 



220 




221 

Valdez to Clearbrook (including all port charges) range from $0.85 to 

$1.24, depending on the capacity utilized. Actual construction time 

is expected to be 24-30 months after all clearances to proceed are finalized. 

This could add an extra two years, barring protracted litigation. The 

line would be fully under U.S. control and would not be subject to Canadian 

Federal or provincial taxes or regulations. 

The known participants in this consortium (officially called the 
Northern Tier Pipeline Co.) consist of the following railroads, consulting 
firms, and small oil companies: Butler Associates, Curran Oil Co., Glacier 
Park Co. (subsidiary of Burlington, Northern), MAPCO, Inc., Milwaukee 
Land Co. (subsidiary of Milwaukee Road), Patrick J. McDonough, and Western 
Crude Oil. Amoco Production Co., was a member but suspended its participation. 
None has a major interest in any refineries to be served by the Northern 
Tier Pipeline, nor do any of the members own any North Slope crude oil. 
Northern Tier claims that it intends to finance the project without 
resorting to throughput agreements — a highly unusual and potentially 
quite expensive approach to pipeline financing. 

The NTP offers several clear advantages over other redistribution 
proposals. The investment would be entirely within the U.S. economy, 
would create numerous construction jobs, and would not add to the bal- 
ance-of-payments deficit. It would be located in the United States and 
would therefore not be subject to foreign controls of any type, including 
the uncertainties of the Canadian permitting process. To minimize 
environmental disturbances the entire line would be buried, and 
railroad rights-of-way would be used for about 400 miles of the line. 
In addition, because more oil would be transported than will be needed 
by refiners in the six Northern Tier States, the extra throughput could 



222 

be marketed to refiners in Illinois. Indiana, and Ohio. It could also 
serve refineries in Puget Sound, the Rocky Mountains, and the Dakotas, 
none of which would be served by any of the other proposed lines. The 
pipeline has an additional advantage in that it could provide a means 
of filling the natural salt caverns of the Williston Basin as a regional 
storage site for part of the Strategic Petroleum Reserve system. 

The NTP, however, also has substantial disadvantages associated 
with it. Financing may prove to be one of the plan's most serious obstacles 
because it does not yet have the support of any of the Northern Tier re- 
finers or the suppliers or purchasers of the North Slope crude oil. NTP 
has said that it will not seek throughput and deficiency agreements 
from shippers or purchasers in order to acquire financing for the pro- 
ject, a financially risky decision. The high capital requirements, probably 
in excess of $1 billion for construction of the line and related facil- 
ities, make NTP the most expensive of the pipeline proposals. This, plus 
design capacity in excess of the needs of Northern Tier refiners, may 
also make financing difficult, especially if PACTEX is approved. 

In addition to being the most costly of the proposals, the NTP would 
require the most new construction and would require the longest completion 
time (as much as 30 months). Because of the need for multiple State permits 
and a Federal environmental impact statement, the NTP could require the 
longest approval time. The NTP consortium has already had difficulty 
in submitting an acceptable permit application to the Washington State 
Energy Facilities Siting Council. The September, 1979, completion date 
given by the NTP Co., therefore, appears overly optimistic. A more likely 
target date, if the permitting process were completed by late 1978, 
would be mid-1981. Northern Tier has requested an environmental impact 



223 

statement by the Bureau of Land Management which will cost $2.5 million 
and will not be completed until April 1979. 

Delays due to environmental opposition are also likely. The key 
environmental issue is the proposal to build and operate a deep- 
water oil-receiving port at Port Angeles, instead of direct tanker de- 
liveries to inner Puget Sound, where oil spills would have a more serious 
impact. It is not yet certain, however, that the Port Angeles facility 
would be environmentally preferable to direct shipments. The State of 
Washington has, in fact, strongly opposed the use of Port Angeles as 
a port for transshipping oil to other States. State and local support 
for the Port Angeles site will probably depend on use of the terminal 
by Puget Sound refineries; if they do not wish to participate, the State 
will probably be less inclined to approve the port. The matter of the 
construction of the Port Angeles facility will require resolution, by 
the Supreme Court, of the Arco vs. Ray litigation to determine whether 
or not the State has the authority to regulate tanker size in Puget Sound. 
If the State is prohibited from such regulation, the local refiners 
would probably prefer direct tanker shipments to their refineries. If 
deliveries to inner Puget Sound are limited to vessels of less than 
125,000 dwt , however, the refiners may be willing to pay the estimated 
delivery fee of $0.19 per barrel from Port Angeles to Anacortes/Cherry Point. 
The NTP consortium has not yet submitted an amended application that would 
meet the environmental objections in Clallam County where the pipeline would 
originate. Washington's Governor Ray has also indicated that a veto of the 
permitting legislation is possible. 



224 

3.2.1.5. Kitimat Pipeline . The Kitimat Pipeline (KP) proposal 
would require construction of a deepwater port and terminal at Kitimat, 
British Columbia, and a 753-mile 36-inch pipeline through which oil 
would be sent to Edmonton, Alberta (Fig. III). The KP, also known as 
the Trans-Provincial Pipeline, would cross the Province of British Columbia 
and part of the Province of Alberta, and its course would parallel an 
existing natural gas pipeline and would utilize part of the existing 
right-of-way for the Trans Mountain Pipeline. Crude oil would be sent 
to Montana, North Dakota, Minnesota, Wisconsin and the Great Lakes Region. 
The Rangeland and Westspur Pipelines would be used to transport the 
oil to Montana. Small sections of new line would be needed to supply 
oil through the Rangeland/Glacier Pipeline to Montana and through the 
Amoco Pipeline to North Dakota. The Trans Mountain Pipeline would also 
continue to move Canadian crude oil to Vancouver and, at least temporarily, 
to the Washington refineries on Puget Sound. These are lines through 
which Canadian oil, which will later be cut off, is now flowing. Proponents 
of the Kitimat proposal claim that by tapping these existing lines and 
the St. Lawrence Seaway, Alaskan oil could be supplied to refineries 
from Puget Sound to Buffalo and as far south as Colorado. 

The Rangeland/Glacier Pipeline system extends south from Edmonton 
into Montana, Wyoming, and Colorado. Between 80 to 100 miles of new 
pipeline would have to be constructed to permit connection of the Range- 
land, Glacier and Westpur Pipelines with Kitimat Pipeline. To connect 
the KP with Amoco 's Mandan, North Dakota, refinery through the Inter- 
provincial Pipeline would require minor new construction. 



225 



Figure III, Proposed Pipeline Routes 




Existing Lines 
Kitimal Proposed Line 
Northern Tier Proposed Line 



California-Texas Line 
Existing 
Proposed 



Source: Chevron, North Slope Oil and the West Coast, Feb. 1977, p, 6 



24-786 O - 78 - 16 



226 

The Kitimat proposal would require the installation of nearly 700 
miles of new pipe and the utilization of about 50 miles of Trans Mountain 
Pipeline, which is now idle. An alternate route would use 300 miles of 
Trans Mountain pipeline and would reduce to 450 miles the distance that 
would have to be traversed with new construction. This alternate route 
would reduce the capital cost of the project by about one-third. 

The consortium sponsors of this line are Ashland, Continental Pipe- 
line Co., Murphy, Farmers Union Central Exchange, Standard Oil (Ohio) 
and Interprovincial Pipeline, Ltd. Sponsorship of the KP, therefore, 
includes Priority 1 refiners in the Northern Tier and several major 
pipeline companies. Some of the suppliers will also be users of the 
surplus crude, a fact which adds impetus to this proposal. Koch industries 
was a member but has withdrawn effective the end of 1977 to build a 
24-inch line from Minneapolis to Missouri to connect with existing lines. 
The new line would cost $126 million and would carry 130,000 b/d from 
Wood River, Illinois, to St. Paul when completed in mid-1979. Koch gave 
up its 26% share because of anticipated delays that would leave its 
St. Paul refinery critically short of feedstock. Sohio replaced Koch 
in the consortium and considers the Kitimat Pipeline a supplement to 
PACTEX as part of its advocacy of both northern and southern west Coast- 
to-Midwest pipelines to move Alaskan crude oil eastward. 

The KP would be a Canadian corporation and would be structured so 
that equity owners would guarantee debt in proportion to their equity 
ownership. Trans Mountain and Interprovincial Pipeline Companies have 
reportedly indicated an interest in owning approximately one-third of the 
system between them and in guaranteeing their share of the debt. On the 
basis of a joint feasibility study, the sponsors concluded that the KP 



227 

was a viable project and have applied to the Canadian National Energy 

Board (CNEB) for the necessary permits and certification. This process should 

be simplified considerably by the fact that the Board has the authority 

to grant both the certificate of public convenience and necessity, and 

the right of eminent domain. The proposal would increase the flow through 

Canadian pipelines and this could expedite the CNEB approval, which will 

probably not be forthcoming until December 1978 at the earliest. 

Once the certification is complete, the sponsors estimate that the 
construction time for the entire system (dock, terminal facilities, pipe- 
line, and pumping stations) would be one calendar year. The developers claim 
that the pipeline could be initially operational with a capacity of 
500,000 b/d within 16 to 22 months after certification. Even though the 
ultimate capacity of the pipeline could be increased to 1,050,000 b/d 
without looping, it would probably be expanded to only 500,000 b/d within 
six years of completion. A 36-inch diameter pipeline was chosen previously 
instead of the announced 30-inch line because of the large potential market 
that would be served by the line. The larger diameter would provide 
more pipeline flow-flexibility because flows could then be varied. 

Based on preliminary engineering and economic feasibility studies, 
the consortium has estimated that the pipeline, terminal, and pumping 
stations will cost approximately $750 million. An average tariff of $0.66 
per barrel from Kitimat , British Columbia, to Edmonton, Alberta, (assuming 
a capacity of 400,000 b/d) would be required over the life of the project 
to {jrovide a return on investment of 9%. The estimated tariff from Valdez 
to Edmonton has been estimated at $0.97 per barrel. It is likely that 
debt financing would be divided among the sponsors based upon the extent 



228 

of their interest in the project, as was done in the case of the Trans- 
Alaskan Pipeline. 

Kitimat, British Columbia has several advantages as a location for a 
tanker terminal . (Fig . IV.) It is located 60 miles from the Pacific Ocean on 
a deepwater fjord that is not only ice-free throughout the year, but also 
significantly trafficked, mostly by ore carriers supplying the aluminum 
plant already located there. The terminal would be capable of receiving 
Alaskan or foreign crude on very large crude carriers. The port is a 
relatively small community and is not near salmon spawning areas or other 
commercially significant fishing grounds. A full assessment of the marine 
terminal site has not yet been completed, so the potential environmental 
impact is unknown. The West Coast Oil Ports Inquiry Commission, however, 
will make a recommendation sometime in 1978 on the socio-economic and 
environmental impacts of the proposed port developement . There has been 
less opposition to the siting of port facilities at Kitimat — certainly 
far less than at Port Angeles, or Long Beach, although it has increased 
in recent months. Most of the concern has been centered on the narrowness o 
the Douglas Channel and the frequent fog, but otherwise the navigational 
conditions at Kitimat are also relatively favorable and would minimize 
the likelihood of oil spills. It is expected that 7 to 13 vessels per 
month, varying in size from 160,000 to 320,000 dwt , would serve the port. 

The advantages of the KP are numerous. Because less than 50% of the 
new pipeline miles required by the Northern Tier Pipeline would be needed 
by the KP, the cost would be about 50% less and the line would be avail- 
able sooner. It would also probably involve the least amount of government 
intervention in the permitting process. 



229 



Figure IV. Proposed West Coast Tanker Routes 




Source: West Coast, August 31, 1977, No. 1, p. 6. 



230 

In addition, there would be economic benefits to both Canada and the 
United States through fuller utilization of existing pipelines. The use 
of 300,000 to 400,000 b/d of spare capacity existing in the Interprovincial 
Pipeline, for example, could minimize investment, keep the tariffs at 
reasonable levels, and offset the decline in Albertan crude reserves. 
If necessary, the system could be economically expanded to move large 
volumes of Alaskan crude oil to Midwestern refineries. Significant 
savings in tanker cost would probably be realized because of the shorter 
distance to Kitimat from Valdez, compared to the other proposed terminals. 
The KP has an additional advantage for Canada in that the line would 
provide all Canadian refiners west of Montreal with access to foreign 
crude through a new deepwater tanker terminal (the only existing one is in 
Portland, Maine.) 

Because of the obvious benefits to Canada, the Canadian Government 
may be willing to assist in developing a means of supplying the Northern 
Tier refiners while the pipeline is under construction rather than phasing 
out their Canadian supplies. This possibility may be enhanced by the 
compatibility of the completion of the KP with the announced Canadian export 
phaseout. The additional volume of oil that would be available to Canada 
through the KP could facilitate exchange agreements with Canada, es- 
pecially for the low-sulfur crudes needed by Northern Tier refiners. 

A potential disadvantage may be that the line would not be under 
U.S. jurisdiction. The KP would not be subject to U.S. review or con- 
trol of tariffs and rates even though it would be transporting U.S. crude 
oil to U.S. markets. There also exists the possibility that one or more 
of the western provinces of Canada might attempt to levy a transit tax 



231 

on this oil, although the historic interdependence in crude oil pipeline 
operations and the recent pipeline treaty have led the sponsors of the KP 
to the conclusion that relations between Canada and the United States 
are not a deterrent to the line. In addition, some western Northern 
Tier States, such as Washington, might not be served by the line. 

In June, 1977, the Kitimat Pipeline Project asked the CNEB to defer 
action on its application for construction permits until a hearing by 
the CNEB was held on a similar proposal by Trans Mountain Pipeline. 
The Trans Mountain action, filed after Kitimat 's, would also have connected 
with existing lines in Edmonton, Alberta, to move the oil to Northern 
Tier refineries. The Kitimat group said that the Trans Mountain proposal, 
if approved by the NEB, would appear to meet the objectives of the group 
sooner and a a lower cost. The group also indicated, however, that 
if the Trans Mountain proposal did not become a reality, it would proceed 
with the Kitimat Project. The Trans Mountain proposal was effectively 
killed by Federal legislation, and the Kitimat consortium has asked 
the CNEB to reactivate its application. 

3.2.1.6. Trans Mountain Pipeline. Reversing the Trans Mountain 
Pipeline has also been suggested as an alternative means of transporting 
both North Slope and foreign crude oil to Northern Tier refineries 
(Fig. III). The refineries at Vancouver do not have facilities for processi 
Alaskan high-sulfur crude oil, but would still have access to Albertan 
crude . 

Atlantic Richfield and the Trans Mountain Oil Pipeline Corporation, 
therefore, have considered the possibility of operating the Trans Mountain 



232 

system on a "yo-yo" basis, because Trans Mountain delivers all the crude 
requirements of the Vancouver refineries in about ten days of pumping 
time. The line is idle the rest of the month. If storage were available 
for the one million barrels of pipeline fill, the line could be reversed 
and Alaskan or foreign crude oil could be pumped for the remainder of 
the month. To unload tankers, Trans Mountain would use the Atlantic 
Richfield dock at the Cherry Point refinery on Puget Sound. As in the 
Northern Tier and Kitimat Projects, however, environmental issues associated 
with increased tanker traffic in environmentally sensitive waters may 
represent a significant barrier to rapid development of the plan. The 
line was the number one target of the condition against oil pollution 
because of increased traffic that it would have generated in Puget Sound. 

The proposal was apparently considered satisfactory to the Kitimat 
consortium which has asked the Canadian National Energy Board to delay 
action on its own application until the Trans Mountain reversal ap- 
plication could be acted upon. The Kitimat Group indicated that if 
the Trans Mountain proposal were rejected, it would proceed with its own 
plans, but if it were approved the plan would meet the objectives of the 
consortium. Trans Mountain was a member of the original Kitimat consortium, 
but later withdrew. The two proposals were very similar except that the Trans 
Mountain plan would not require any new construction to connect with the 
pipelines extending southeastward from Edmonton and, therefore, would be avail- 
able much sooner and presumably at a lower cost. The plan, however, was killed 
in Oct. 5, 1977, by the Magnuson Amendment to the Marine Mammals Protection Act; 
which prohibits any new crude oil facility on Puget Sound east of Port Angeles. 
The plan could be revived only by Presidential veto of the Act. 



233 

3.2.1.7. Four Corners Pipeline . Although it is small compared 
to the scale of the other pipelines, the Four Corners Pipeline will 
carry some of the Alaskan oil surplus. The re-versal of the existing 
line is expected to be completed by Atlantic Richfield in spring 1978 
and will extend from Long Beach to Colorado. It will initially carry 
28,000 b/d, but if the economics are encouraging this could be increased 
to 140,000 b/d by adding more power to the pumps. The line was originally 
built to carry 70,000-140,000 b/d but was moving only 3,0003,500 b/d 
when purchased by ARCO. The reversal and upgrading is expected to cost 
$12 million. After arriving at the Four Corners area, the oil will 
either be sold to small refiners in northwest New Mexico or moved into the 
Texas-New Mexico Pipeline for shipment to Houston and other refining centers 
in the Southwest. 

3.2.1.8. Direct Deliveries by Tanker . Several long-term alternatives 
to pipeline transportation have been considered by the petroleum industry. 
These include LOOP, SEADOCK, TransPanama, Trans-Guatemala, Cape Horn, 
and the Northern Passage (Fig. V) . None of these alternatives would 
directly serve the Northern Tier States but would provide a means of 
redistributing the West Coast surplus of crude oil to Gulf Coast ports. 
A small percentage of this oil may eventually find its way to Northern 
Tier refiners or may displace other oil that could then be sent there, 
but the Transportation system does not exist to facilitate more than 
a small displacement. Transporting oil by tankers from Valdez to ports 
in the Gulf of Mexico for refining or for forwarding through existing 
pipelines, however, is seen by the industry as a costly, short-term expedient. 



234 




MAJOR ALTERNATIVE TRANSPORTATION SYSTEMS FOR THE 
EASTWARD MOVEMENT OF NORTH SLOPE CRUDE 



235 

Although several oil companies have stated that they will be able to 
handle their oil surplus with their own tanker fleets, they have stated 
a preference for pipelines originating on the West Coast. 

Tankers of up to 65,000 dwt can pass through the Panama Canal fully 
loaded, and larger ships (up to approximately 90,000 dwt) can use the Canal 
only if partially loaded. Larger tankers (over 90,000 dwt) would have 
to be routed via Cape Horn or would have to be offloaded into smaller 
tankers at the western entrance to the Canal. The oil companies claim 
that shipment of the surplus crude oil in small tankers westward through 
the Panama Canal would be an inefficient use of energy and would be 
very expensive adding $1.50 to $2.00 per barrel to the cost of the tanker 
run to the West Coast. In spite of these disadvantages, some of the oil 
will probably be moved through the Canal, at least until more suitable 
systems are available. 

The limited availability of sufficient Jones Act tankers may be a 
major limitation. Unless North Slope crude oil is exempted from the 
Jones Act, which requires oil moved from one U.S. port to another to be 
carried in U.S. flag ships, it will have to be shipped via Jones Act 
tankers. By 1978, the supply of available Jones Act tankers may be suf- 
ficient to carry 200,000 to 250,000 b/d of the West Coast surplus to the 
Gulf Coast, although not all Jones Act tanker owners are likely to com- 
mit their ships to the run. Because of other commitments, probably less 
than two-thirds of the Jones Act tankers will be available for the move- 
ment of Alaskan oil. By late 1978 or early 1979, the delivery of ad- 
ditional Jones Act tankers now on order is expected to increase this 
capability to 400,000 b/d (less than two-thirds of the expected surplus). 



236 

On Oct. 22, 1977, foreign-flag tankers were permitted by a U.S. District 
Court decision to carry Alaskan oil to the Virgin Islands for refining 
and transshipment to the mainland. The Department of Commerce may also 
grant conditional waivers of the Jones Act for subsidized tankers of U.S. 
registry . 

Because of the prospect of a shortage of Jones Act tanker capacity, 
subsidized U.S. flag ships presently in international service have been 
given special limited permission by the Federal Maritime Administration 
to transport Alaskan North Slope oil to U.S. ports. These ships are 
prohibited from engaging in Alaskan oil traffic for more than six months 
each year and from carrying the oil to the Atlantic side of the Panama 
Canal, although most of the vessels are 100,000 dwt or larger and would 
not be able to negotiate the Canal under any circumstances. The number 
of tankers that will actually participate in this traffic is not yet 
known, but it may be about one dozen. This would raise the fleet capacity 
to 500,000 b/d, but it could drop as low as 400,000 b/d on occasion. It 
is far from certain that the Federal Maritime Commission or Congress 
would be willing to permanently relax the cabotage laws enough to ensure 
a tanker fleet adequate to handle the volume of surplus oil that is likely 
to be generated on the West Coast when the Trans Alaska Pipeline reaches 
full capacity, but in the absence of a transcontinental pipeline it might 
be possible. 

Because of the high cost of using small tankers and the Panama Canal, 
it may be more advantageous to employ very large crude oil carriers 

_3/ Section 27(b) of the Alaskan Statehood Act preserved the jurisdiction 
of the Federal Maritime Commission over water transportation on the 
high seas between ports in Alaska and ports in the other 48 States. 



237 

(VLCCC's) of 200,000 dwt or more, to transport the oil around Cap Horn 
to markets in the eastern United States. This would be a long trip, 
however, and the high cost (about twice as much per barrel as the per bar- 
rel cost associated with the proposed pipelines) of such an extended 
voyage would probably be considered prohibitive. Both the Panama Canal 
and Cape Horn routes, because of the use of inefficient tankers on the one 
hand and the extremely long tanker hauls on the other, are likely to be 
practical solutions to the problem of surplus oil on the West Coast only 
if construction delays are encountered in building a pipeline system. 

To accommodate the tanker movement of West Cost oil, two offshore deep 
water crude terminals have been proposed for the Louisiana and Texas Gulf 
coasts. The Louisiana Offshore Oil Port (LOOP) would be located 19 
miles south of Grande Isle near St. James, Louisiana and would send oil 
through the Capline system, which is currently operating at capacity 
and would require expansion before additional volumes of crude could be 
moved north from St. James. The first stage of LOOP is planned for 
completion in 1980 and would handle 1.4 million b/d. The second stage 
(an additional 1 million b/d) would cost $191.5 million and would be 
completed in 1982. The third stage would cost $269.4 million when finished 
in 1989, and would increase the capacity to 3.4 million b/d. The partners 
in LOOP are Ashland, Marathon, Murphy Oil Corp., Shell, Texaco, and 
Union Oil of California. LOOP is proceeding with construction plans after 
receiving the DOT license on August 1, 1977, and a State licence soon after 

SEADOCK would require construction of a deepwater terminal 25 miles 
off Freeport , Texas, in the vicinity of Houston. The first phase would 
cost $659 million and would permit the offloading of 2.5 million b/d. Oil 



238 

would be sent from Freeport through the Texoma, Seaway, and Explorer Pipe- 
lines to Tulsa and Chicago. After reaching Tulsa, the oil could be moved 
to Northern Tier States through the Williams Pipeline if it is expanded. 
The proposed expansion would result in a capacity of 350,000 b/d for oil 
being transported from Tulsa to Minneapolis. There were eight stockhol- 
ders in the project: Cities Service, Conoco, Crown Central, Dow Chemical, 
Exxon, Gulf, Shell, and Phillips. Mobil had been a shareholder but with- 
drew on June 1977 ostensibly because of terms and conditions imposed 
by the Department of Transportation. In July 1977, Exxon and Gulf also 
withdrew, casting doubt on the future of the project. In August 1977, 
Seadock cancelled all engineering and pre-construction contracts. 

The LOOP and SEADOCK proposals are designed to facilitate VLCC 
transportation of crude oil at relatively low cost to the refining centers 
on the Gulf Coast and in the Midwest and Great Lakes area. No deepwater 
ports capable of handling supertankers currently exist on the Gulf or 
East Coasts, so at least one of these two proposals would be necessary 
to permit the use of VLCC's. Both systems would be only limited 
solutions to the problem of West Coast oil redistribution, because of the 
great distances involved. Refiners in the States of Washington, Montana, 
and North Dakota might be supplied with a small pipeline from Puget Sound. 
If no transcontinental pipelines were built. North Dakota refiners would 
probably be better served with displaced domestic crude oil that would 
otherwise be sent to markets that have better access to West Coast or forei 
crude oil. The Northern Tier refineries would also be less able to use 
the relatively high-sulfur oil from Alaska and foreign sources than some 



239 

of the refineries near the Gulf Coast. If Alaskan oil is priced low 
enough, it could sufficiently compensate Northern Tier refiners to over- 
come the higher refining costs of Alaskan oil. If this happens, however, 
it would probably make the transcontinental pipeline proposals even more 
attractive . 

To shorten the length of VLCC tanker hauls around Cape Horn, two 
related proposals have been made, both of which would require the use of 
short pipelines across the Central American isthmus. One proposal is 
for a pipeline to be built across Guatemala; the other would use an 
existing U.S. Navy-owned pipeline running parallel to the Canal. Both 
of these alternatives would require deepwater terminals on the Pacific 
side to accommodate the offloading of VLCC's. Smaller tankers would 
probably be used on the Caribbean side so that conventional U.S. ports 
could be utilized. 

The CAPICO (Central American Pipeline Company) Line is proposed 
for construction between Las Lisas and San Francisco del Mar, Guate- 
mala. This ambitious project would be constructed to carry worldwide 
oil shipments, according to CAPICO, regardless of whether or not one or 
or more of the other pipelines are built. The developer claims that 
the line would have an initial capacity of 800,000 b/d and could eventual- 
ly reach 1.6 million b/d. It proposes to use 250,000 dwt tankers from 
Valdez to Las Lisas and tankers of approximately 65,000 dwt from San 
Francisco del Mar to U.S. Gulf and Atlantic ports. CAPICO claims it would 
be able to deliver crude oil from Valdez to New York, for example, 
for $1.82 per barrel. 



240 

There appears to be little support, however, for the Guatemala 
pipeline. It is seen as much too vulnerable politically and strategical- 
ly, and even though it is potentially less expensive than tankers via the 
Canal or the Cape, it may not be economically feasible as a long-term alter 
native. The Central American Pipeline Co. has claimed that it will build 
the line in spite of these objections. 

The Navy pipeline across Panama is presently not in use. It is 
unlikely that it will be used for West Coast oil redistribution, however, b 
cause of a U.S. agreement with Panama by which the United States will not 
implement any mode of transport that would compete with the Canal. In 
any event, its capacity would probably be insufficient for this purpose 
and high costs would probably be incurred if it were expanded. The same 
national security problems that applied to the Trans-Guatemala route 
would also be limiting factors in this case. 

Another possibility, although not an imminent one, is the use of 
VLCC's via the Northwest Passage, bypassing the Trans-Alaskan Pipeline 
altogether. The Department of Transportation has recommended this alter- 
native as being the least expensive method of delivering Alaskan crude 
oil to refineries on the East Coast. This method was attempted by 
Humble Oil (now part of Exxon) in its experiment with the S.S. Man- 
hattan, an ice-breaking supertanker that was designed for the specific 
purpose of transporting Alaskan crude oil to the Eastern United States 
by the shortest possible route. .The ship was able to make the passage 
during the most favorable months, but several times it required assistance 
from accompanying Canadian icebreakers after becoming icebound. One in- 
cident left a large tear in the hull that would have produced a major 
spill had the ship been carrying oil at the time. It was also discovered 



241 

that ice-heaving in the shallow waters of Prudhoe Bay effectively pre- 
vented the construction, with current technology, of offshore terminals 
that would be necessary for the loading of ice-breaking VLCC's. 

3.2.1.9. Movement by Tank Car Unit Trains . The use of unit tank 
trains, primarily to supply Northern Tier refiners, has also been proposed 
as a means of reducing the West Coast oil surplus. Breakthroughs in 
loading and unloading techniques make this an increasingly promising 
alternative, although it is one of the more expensive options. Recent 
innovations in tank car technology have made them competitive with pipelines 
in some situations, but it is not yet certain whether or not this is 
one of them. TANK TRAIN is a product of the General American Transportation 
Corporation (GATX), and it consists of a system of interconnected 
tank cars in five 18-car strings, which two men can load or unload 
49,607 barrels in less than six hours. According to GATX, TANK TRAIN con- 
cept was tested for two years before it was offered commercially in late 1975. 
In early 1976, the first commercially operated TANK TRAIN cars were 
used to distribute residual (No. 6) fuel oil. 

Rail transportation of large volumes of crude oil by tank is not 
new. During World War II, most domestic crude oil was transported in 
that manner because tankers were diverted to war duty and were subject 
to submarine attack. Since 1974, the Southern Pacific Railroad has 
successfully operated four 70-car unit trains carrying 37,000 barrels 
of crude oil in 23 ,000-gallon tank cars for Standard Oil of California 
from Salt Lake City to its refinery in Richmond, California, 800 miles 
away. Railroads currently derive about 2% of their revenue from rail 

24-786 O - 78 - 17 



242 



transportation of petroleum. As of 1976, there were 170,876 privately- 
owned tank cars in existence and more are being built. 

The GATX proposal would use the Burlington Northern Railroad and 
the Portland Pipeline for a rail link from Port Westward, Oregon or 
Puget Sound, Washington to Cut Bank, Montana, and Minot , North Dakota. 
The proposal was described in "Unit Train Transport of Alaska Oil from 
the West Coast to the Midwest" by Arthur M. Hughes of the Federal Energy 
Administration's Office of Coal: kj 

Burlington Northern Railroad is negotiating for existing 
facilities at Port Westward, which is an existing port used 
by the U.S. Army for Far Eastern supply since World War II. 
Far from any population centers, this port now has facilities 
for docking 35,000-ton ships and higters. The port can be 
ready for service in six months. 

The facilities at Port Westward could load up to 300,000 
barrels of oil daily (six 90-car trains) directly from 35,000 
ton tankers or lighters. Each train could be loaded in six hours 
by two men. The system would be designed to capture and 
minimize oil spills. From Port Westward, the unit trains would 
move to Cut Bank, Montana and Minot, North Dakota. At Cut 
Bank, they could discharge into the continental pipeline with 
a capacity of 88,000 b/d. This pipeline serves three 
refineries at Billings, Montana. At Minot, the trains can off- 
load into the Portal pipeline (capacity 100,000 b/d) and the 
Amoco pipeline (up to 51,000 b/d could go on the Clearbrook, Min- 
nesota to offload into the Minnesota pipeline (capacity 190,000 
b/d) or the Lakehead line (capacity 1,555,000 b/d). 
Facilities at Cut Bank, Minot and Clearbrook can be readied 
in six months, while the facilities at Port Westward or Puget 
Sound are upgraded. Most of the track between Port Westward and 
Clearbrook is the Burlington Northern's main line. It is in 
good condition and would not require any significant upgrading 
or improvements to handle the additional six trains per day 
representing 200,000 b/d. 



kl Unit Train Transport of Alaska Oil from the West Coast to the Mid- 
west, Arthur M. Hughes, Federal Energy Administration, Office of 
Coal, July 2, 1976, p. 7-9. 



243 



The tank cars could be built at a coast of about $45,300 by GATX 
and could be delivered about six months after receipt of the order. 
GATX could also subcontract the manufacture of cars to other companies 
or could convert existing tank cars to unit train operation. To move 
200,000 b/d, almost 3,800 cars would be needed. (Table II). 

If tank trains were used to directly supply the refineries at a 
volume of 360,000 b/d, 5994 tank car would be needed at a lease cost of 
$34,417,548 per year. If tank trains were used to supply pipelines 
serving refineries the requirement would be 4,768 cars at a cost of 
$27,377,856 per year. The Burlington Northern Railroad has told GATX 
that it would probably file a tariff of $2.80 per barrel to transport 
crude oil direct from Puget Sound to Saint Paul. This tariff would not 
include tank car rental, switching charges, the cost of a Pacific 
Coast terminal, or the costs of loading and unloading the tank cars. 
Table II shows the likely per-barrel charges for rail unit-train 
movement of crude oil to the Norther Tier States. 



TABLE II 



CARS NEEDED FOR UNIT TRAIN OPERATIONS PORT WESTWARD TO MINOT 



BBL/DAY 



NO. TRAINS 



NO. CARS 



50,000 
100,000 
150,000 
200,000 
300,000 



7 
14 
21 
28 
42 



1,260 
1,890 
2,520 
3,780 



630 



244 
TABLE III 

CHARGES PER BARREL FOR RAIL UNIT TRAIN MOVEMENT 5/ 



Destination 


BBLD/Per Day 


Tank Cars 


Charge 






Required 


Per Barrel 


St. Paul 


200,000 


3,168 


3.21 


Billings 


100,000 


891 


2.09 


Bismarck 


50,000 


594 


2.53 


Superior 


40,000 


642 


3.22 


Laurel 


50,000 


402 


2.08 


Wrenshall 


20,000 


297 


3.09 



Another GATX proposal would move Alaskan crude oil from Long 
Beach, California, to Midland, Texas, in volumes of up to 150,000 b/d. 
From there, existing pipelines would complete the distribution to 
refineries. There are several railroads that could participate in 
this proposal, including the Atchison, Topeka, and Sante Fe Rail- 
way, the Missouri Pacific Railroad, and the South Pacific Transportation 
Company. Santa Fe and Southern Pacific have indicated that, because 
of heavy traffic congestion in the Long Beach area, there would be 
a 100,000 b/d limit on the amount of crude oil that could be moved 
from there by rail. To avoid this problem, they have proposed loading 
the cars at a point east of Long Beach, such as Corona, Colton, or Indio. 
If Corona were used, 2,079 TANK TRAIN cars would be needed to move 
150,000 b/d to the area of Sweetwater /Midland , Texas at a cost of 
$444,364 per trip. 

_5/ Tank Trains for the Northern Tier Refineries, General American 

Transportation Corporation for the Department of Transportation, 
Planning Document GS 462.18.3.-21, June 9, 1976. 



245 

The advantages of the unit tank train concept for the redistribution 
of the West Coast oil surplus are numerous. The trains are technically 
feasible and rapidly available. They could be delivering up to 300,000 
b/d to existing Midwestern pipelines within 6-12 months, whereas the 
proposed pipelines may not be available for several years. The invest- 
ment requirement for tank trains is lower than for pipelines carrying 
up to 350,000 b/d. There would be a lower risk and a greater flexib- 
ility in supplying refineries by train tran by pipelines if there were 
a sudden change in crude oil sources caused by embargoes of imported 
oil or other changes in the distribution patterns. At the end of the 
West Coast surplus, the tank cars could be sold to other operators 
and used where needed. There are virtually no environmental problems 
associated with the tank trains because they are completely closed 
systems to eliminate spillage and to facilitate the collection and 
disposal of vapors. In appropriate supply and demand situations, it 
may be possible to arrange backhauls of compatible liquids and slurries 
to lower the cost of moving the oil one way. Tank trains would also 
generate additional revenues for U.S. railroads with fixed plant facil- 
ities and excess capacity. 

There are also substantial disadvantages to this concept. Tank 
trains may not be competitive with pipelines if pipeline volume exceeds 
350,000 b/d. Even though tank trains require a much lower initial capital 
investment than comparable pipelines, the operating cost could be as much 
as 2 1/2 to 5 times higher. The economics would be improved, however, 
if unit train rates were included in the entitlement base for refiners 
of Alaskan oil, which would partially subsidize the transportation cost. 



246 

The operating cost of the railroads may be more vulnerable to inflation 
than pipelines, and this could eventually make tank trains uncompetitive. 
The tank car lessors, such as GATX, would probably want some guarantees 
of long-term commitments before they would begin to manufacture tank 
cars on a large scale, and these guarantees might be difficult to 
obtain. Most refiners consider the unit train concept to be the last 
resort or, at best, a short-term expedient, primarily because of the 
high cost. Exchange agreements with Canada may also make such trains 
unnecessary, at least until pipelines could be built. Unit trains 
might not serve to move surplus Alaskan oil so much as low-sulfur 
Indonesian crude oil that could be more readily used by the Northern 
Tier refiners. 

3.2.1.10. Exchanges and Exports . A three-way trade of crude 
oil between the United States, Canada, and Japan has also been proposed 
as an immediately available short-run solution to the problem. Under 
this proposal, surplus Alaskan crude oil would be shipped to Japan 
to supplant part of its OPEC imports. Part or all of the OPEC oil 
thus displaced would be shipped to Eastern Canada, either directly 
by tanker or indirectly by pipeline through Portland, Maine, for 
processing in refineries in Nova Scotia or in Quebec. This oil in 
turn, would displace Canadian oil which is produced in Alberta, and shipped 
eastward by pipeline from Edmonton to Sarnia and on to Montreal. The 
Albertan crude oil, according to this plan, would then be available to 
Northern Tier refineries which are designed to handle that type of oil, 
because it was their primary supply prior to the initiation of Canada's 



247 

self-sufficiency program following the Arab oil embargo. This alternative 
has received considerable attention, because there are potential economic 
advantages for all concerned and, because it does attempt to deal directly 
with the Northern Tier supply problem as well as the issue of Alaskan 
oil redistribution. 

Despite the fact that exports of Alaskan oil to Japan would have 
obvious environmental advantages for California (new pipelines and 
deepwater ports would not be needed on the West Coast), there are off- 
setting disadvantages. United States ships would not be required for 
use in an exchange of the type proposed and the proposal would thereby 
deprive the depressed U.S. Merchant Marine of potential jobs. Because 
tankers registered under flags of convenience are not as closely regulated 
as U.S. tankers, there may be an increased likelihood of a major oil 
spill that could eventually reach the West Coasts of Canada and the 
United States. Another serious disadvantage of the exchange proposal 
is that if Alaskan oil is exported because of a lack of adequate refining 
capacity on the West Coast, another embargo could once again create 
an oil shortage because there would still be no means for transporting 
or domestically refining surplus Alaskan crude oil. 

Lower cost is a major advantage of the exchange proposal. Because 
the distance from Alaska to Japan is only a fraction of the distance to 
the Gulf Coast via the Panama Canal and because the international traf- 
fic would permit the use of low-cost foreign shipping, the cost of moving 
a barrel of North Slope crude oil would be about $1.50-$2.00 per barrel 
less than on U.S. tankers. This transportation savings would permit a 
higher wellhead price which would benefit the State of Alaska because it 



248 

calculates its royalties and severance taxes on the basis of that price. 
This savings would also directly increase the oil companies' profits on 
North Slope production. 

At the time authorization for the Trans Alaska Pipeline was being 
sought, there was considerable concern that the companies involved might 
have selected thr^t route to maximize their profits through export rather 
than through domestic marketing. As a result of public and congressional 
concern over this possibility, the Trans Alaska Pipeline Authorization 
Act (P.L. 93-153) prohibits exports of Alaskan North Slope crude oil to 
noncontiguous foreign countries unless the President makes specific 
findings with the concurrence of Congress that it is in the national 
interest to do so and that such exports will not diminish the quality 
and quantity of petroleum available to the United States. The Act does 
not preclude exchanges of Alaskan oil with the contiguous countries of 
Canada and Mexico, and neither Presidential nor congressional approval 
is required to effect such an exchange. 

Such exports are also subject to the Export Administration Act of 
1969, however, and this was amended by P.L. 95-52 on June 22, 1977. The 
revision prohibits the exportation of domestically produced crude oil 
transported over a right-of-way granted pursuant to section 28 of the 
Mineral Leasing Act of 1920 except (1) for exchanges of crude oil in 
similar quantity for convenience or increased efficiency of transporta- 
tion with persons or the government of an adjacent foreign state, or 
for oil that is temporarily exported for convenience or increased ef- 
ficiency of transportation across parts of an adjacent foreign state and 
reenters the United States, or (2) where the President makes and publishes 



249 

an express finding that the export of such oil will not diminish the 
total quantity or quality of petroleum available to the United States, 
that such export will have a positive effect on consumer oil prices 
by decreasing the average of refiners' crude oil acquisition costs 
as a result of allowing such exports, and that such export is in the 
national interest and is in accord with the provisions of the Export 
Administration Act of 1969. The President must admit such findings 
to the Congress, and the export may not take place until the expira- 
tion of a 60-legislative-day period during which either House of Congress 
may veto the proposed export by the passage of a resolution of disap- 
proval. Any such resolution shall be considered under expedited procedures. 
The substitute further requires that any contract for the export or 
sale of such oil may be determined if the petroleum supplies of the 
United States are interrupted or seriously threatened. This provision 
shall be in effect for 2 years. 

The conference stated its intent that this provision for possible 
oil swaps should be utilized only under circumstances where it is clear 
in the interest of the United States and of U.S. oil consumers and 
where there will clearly be no potential danger to long-terra U.S. energy 
interests . 

Japan has expressed an interest in such an exchange, but the Canadian 
position is less clear. Both countries would benefit at least partially 
from the lower transportation costs. The Canadian policy has been 
to accept only U.S. oil production (as opposed to imports) in exchange 
for Canadian oil, although Canada is now accepting "secure" oil which 
may include oil originally imported to the United States. The recent 



250 

policy of the United States has been to remove disincentives to commercial 
exchanges, as indicated by the FEA waiver of the oil import fee when 
oil is imported from Canada as past of an approved exchange. To facilitate 
such exchanges, the Department of Commerce and FEA have developed 
standards and procedures for the consideration of export applications. 
For its part, the Canadian National Energy Board has already approved 
one exchange of this type and has approved in principle several others. 

A major factor working against a three-way exchange with Canada 
may be the completion of the Trans Canada Pipeline connecting the pro- 
ducing areas in Alberta with the refineries in Ontario and Quebec. Be- 
cause it needs the revenue to amortize the high construction costs, 
Canada may not be willing to reduce the throughput in that line to 
supply Northern Tier refiners through existing lines. If that proves to 
be the case, there may well not be enough exportable Albertan crude oil 
available to Northern Tier refiners to justify a three-way exchange. 
In addition, Canada is attempting to reduce imports of foreign oil 
for more foreign oil now that it has the means to move it to its eastern 
provinces. In fact, it was to avoid such vulnerability to interruptions 
of foreign supply that prompted the building of the Trans Canada Pipe- 
line initially. Except for exchanges, Canada will be stopping entirely 
its exports of light oil by 1980 and its heavy oils by 1986. The current 
level of such exchanges is about 60,000 b/d and is done primarily 
for the convenience of refiners in both countries. Canada, therefore, is 
crucial to the success of exchanges but is not likely to be a willing 
participant on a large scale. 



251 

The export option was effectively killed in July 1977, when President 
Carter declared that he would not permit Alaskan oil to be exported. 

3.2.1.11. Shutting in North Slope Production . If sufficient Jones 
Act tanker capacity or transcontinental pipeline capacity is not available, 
the only immediate alternatives would appear to be exports or exchanges 
with other nations or shutting-in the surplus producing capacity in 
Alaska. To do the latter would adversely affect companies holding leases 
on the North Slope, especially Standard of Ohio, which is a "small" major 
oil company that has concentrated nearly all of its domestic production 
efforts on North Slope development. A potential reduction in the Nation's 
balance-of-payments deficit would be lost if production were shut-in.. 
In addition, delays in recoupment of capital by the Alyeska Consortium 
and the leaseholders would probably eventually result in higher prices 
to the consumer. The State of Alaska would suffer, at least in the short 
term, because it would lose considerable revenues from not receiving 
all of the production royalties and severance taxes that it has programmed 
into its budget. This particular option is generally considered to 
be the least desirable and one to be avoided if at all possible, because 
it would not solve the problem, because it would place a great financial 
strain on the companies involved, because it would not provide the 
Northern Tier refiners with domestic crude oil, and because it would 
not reduce foreign oil imports or the balance-of-payments deficit. 

3.2.12. Summary . The problem of a West Coast oil surplus in the 
face of rising imports in the rest of the country is a simple problem, 
but its solution is far more complex. A variety of redistribution plans 



252 

have been proposed, none of which appears certain to be implemented, 
although some seem more likely than others. In addition to the certainties 
of the Four Corners Pipeline and tanker transit through the Panama Canal, 
the most promising prospects at present are the PACTEX Pipeline, the 
Northern Tier Pipeline, the Kitimat Pipeline, and the LOOP Deepwater 
Port. Most of the other plans appear to be either economically impractical 
or politically undesirable. For both security and political reasons, 
the President has already ruled out exchanges or exports to Japan, 
despite the fact that the economic benefit would be higher than for 
any other option, that such trade could begin immediately, and that 
it would involve no environmental damage from new construction. In 
the absence of that immediate option, movement of the oil by tanker 
through the canal is the only alternative. At least one Gulf Coast 

« 

superport , LOOP, will probably be built if financing and permitting 
difficulties can be overcome. PACTEX appears to be a practical plan, 
but has faced strong environmental opposition from the State of California, 
although that impasse appears to be near an end. The Northern Tier 
and Kitimat Pipelines are also faced with environmental problems which 
would result in increased tanker traffic along sensitive coastlines, 
and consequently their futures are uncertain. At least one of these 
lines is likely to be built, however, in order to supply Northern Tier 
States. 

It cannot be said with certainty at this time which of these 
proposals will succeed. The problem is large enough to permit several 
competing systems to be constructed and to be operated profitably. 
New proposals and refinements of old ones are sure to come as some 



253 

uncertainties vanish, such as the rate to be met for oil via the Trans 
Alaskan Pipeline. 

The most serious delays to the pipeline projects and deepwater 
ports have been caused by the need to obtain Federal, State, and local 
permits. The latter have been particularly troublesome for the 
sponsors of the transcontinental pipelines, although the Federal permit- 
ting process could delay these projects even further. Most of the 
legislation introduced so far in the 95th Congress has been either to 
ban exports entirely or to expedite the necessary Federal permits. If 
the delays at the State level cannot be overcome through the normal 
processes, it may become necessary for Congress to resolve the matter. 
If the solution to the problem of the West Coast oil surplus is found 
to be in the national interest, as it is certain to be, the Federal Govern- 
ment can preempt the States on the basis of facilitating interstate coimnerce 
as it did in the case of the Natural Gas Act. The consequences of 
inaction, should these delays continue for long, could be detrimental 
to the economic well-being of the Nation. 

The 95th Congress has not yet acted on these matters, although the 
following bills have been introduced: 

S. 1868 (Melcher) 

Expedites issuance of Federal permits and development of transporta- 
tion system to move Alaskan crude oil. 

H.R. 5840. (Zablocki) 

Export Administration Act Amendments and Extension. Contains 
compromise amendment similar to Section 28(u) of the Mineral Leasing Act. 



254 

An additional finding was added which would require that any proposed ex- 
port exchanges benefit consumers. Would require that exports of Alaskan 
oil be made only pursuant to contracts which may be terminated if the 
petroleum supplies of the U.S. are interrupted or seriously threatened. 
The energy action procedures of the Energy Policy and Conservation Act 
would be modified to require a waiting period of 60 days before exports 
can begin and would permit either House to block a proposed exchanges. 
The House had earlier voted 240-166 to prohibit exports of Alaskan oil. 

H.R. 312 . (Conte) 

Amends the Trans-Alaska Pipeline Authorization Act and the Mineral 
Leasing Act of 1920 to direct the President to develop a plan for an 
equitable system of transportation, allocation, and distribution of Alaskan 
petroleum resources to all areas of the United States. 

H.R. 2332 (McKinney) 

Amends the Mineral Leasing Act of 1920 to prohibit exports of 
domestically-produced and pipeline-transported crude oil to foreign 
nations with the limited exception of exchanges or temporary exports for 
convenience or increased efficiency of transportation. 

HEARINGS 

U.S. Senate Congress. Senate Committee on Interior and Insular 
Affairs and Commerce. Problems in transporting Alaskan North Slope 
oil to domestic markets. Joint hearings, 94th Congress, second session. 
Part 1. Sept. 21, 1976. Washington, U.S .Govt., Print. Off., 1976, 
121 p. 



255 

U.S. Congress. Joint Economic Committee, Canadian Oil Policies 
and Northern Tier alternatives. Hearing, 94th Congress, second ses- 
sion. September 13, 1976. Washington, U.S. Govt. Print. Off., 1977. 
217 p. 

REPORTS AND CONGRESSIONAL DOCUMENTS 

U.S. Congress. General Accounting Office. Survey of publications 
on exploration, development, and delivery of Alaskan oil to market; re- 
port to the Senate Committee on Interior and Insular Affairs. Washington 
U.S. Govt. Print. Off. , Jan. 14, 1977. 40 p. (94th Congress, second ses- 
sion. Senate. EMD-77-11. 

U.S. Congress. Senate. Committee on Energy and Natural Resources. 
Alaska oil price policy: Committee print. Washington, U.S. Govt. Print. 
Off., 1977. 284 p. (95th Congress, 1st session. Senate. Publication No. 
95-14). 

U.S. Congress. House and Senate. Summary of responses to Joint 
Committee questionnaire on potential problems associated with the delivery 
of crude oil from Alaska's North Slope. Committee print. Washington, 
U.S. Govt". Print. Off., 1976. 372 p. (94th Congress, 2d session, Senate, 
Serial No. 94-43 (92-133)). 

ADDITIONAL REFERENCE SOURCES 

Corrigan, Richard. Now that the pipeline's almost built, who's 
going to take the oil. National Journal, Dec. 11, 1976: p. 1762-1768. 

U.S. Department of the Interior, Bureau of Land Management, Draft 
environmental impact statement, executive summary, crude oil transportation 



256 

system Valdez, Alaska to Midland, Texas. Department of the Interior, 
Washington, D.C. 1977. 

Federal Energy Administration, Office of Oil and Gas, Crude oil 
supply alternatives for the Northern Tier States. Prepared for the Com- 
mittees on Interior and Insular Affairs of the Senate and the House of 
Representatives. Washington, D.C, August 1976. 

Port of Long Beach, Environmental Affairs Division. Overview: 
SOHIO-West Coast to Mid-Continent Pipeline Project. Long Beach, January 
1977. 41 p. 

Sohio Transportation Company. West Coast — Mid Continent Pipeline 
Project. Cleveland, June 1976. 46 p. 



257 

3.2.2. Additional Crude Oil Pipeline Capacity in Alaska . ^/ 

During the summer of 1968, a large concentration of oil was discovered 
on the Alaskan Coast near Prudhoe Bay. The oil resources of the North Slope 
were subsequently estimated at over 30 billion barrels, which started a 
leasing and drilling boom that is still underway. Since then the limits 
of the Prudhoe Bay field have been extended and recent evidence suggests 
that the area contains even more oil than originally estimated. 

These discoveries have stimulated interest in other potential oil- 
producing areas along the North Slope. One of these areas, Naval Petroleum 
Reserve No. 4, has been known to contain oil deposits since early in this 
century. NPR 4 has a coastal area of about 37,000 square miles that lies 
in a sedimentary basin on the North Slope, west of the Prudhoe Bay field. 
Between 1944 and 1953, the Navy explored the reserve and conducted a limited 
drilling effort in shallow formations that yielded discoveries verifying 
the presence of petroleum. The geologic structure of NPR 4 is very similar 
to that of Prudhoe Bay, especially along the Arctic Coastal Plain. The 
discovery of substantial amounts of oil and gas at Prudhoe Bay informations 
deeper than those drilled by the Navy indicates that there may also be 
large petroleum deposits in the same formations in the reserve. Existing 
information indicates at least one structural high in NPR 4 with an area of 
100 square miles, and there is a possibility that there may be as many 
as five other comparable stuctures. 

Without additional information, it is impossible to determine the extent 
and producibility of the petroleum reserves in NPR 4. More information will 

*/ Prepared by David M. Lindahl, Analyst, Environment and Natural Resources 
Policy Division. 



24-786 O - 78 - 18 



258 

soon been forthcoming, however, with renewed plans for the exploration 
and possible development of the area. Under provisions of the Naval Petroleum 
Reserves Production Act of 1976, jurisdiction over NPR 4 was transferred 
from the Navy to the Department of the Interior, where responsibilities for 
the administration of the program were assigned to the U.S. Geological 
Survey. Plans have been announced by the USGS to continue exploratory dril- 
ling in 1978. The latest estimate of the Department of Energy, based 
on existing limited information, indicates that at least 5 billion bar- 
rels of oil and gas condensate and 14.3 trillion cubic feet of gas may 
be present there. 

Another major field is being developed on the Alaskan Coast about 55 
miles east of Prudhoe Bay. Several successful wells have provided strong 
evidence to suggest that the area could produce large quantities of petro- 
leum and that it may be larger than originally throught. Exxon, the owner 
and developer of the leases, is not yet certain that the find is large 
enough to justify the high costs of drilling, development, and pipe- 
lining, but it does consider it "a major accumulation" and "a good-sized 
field." 

The significance of these discoveries plus additional finds at Prudhoe 
Bay has yet to be determined. If they prove to be commercial deposits 
worthy of development, it will be necessary to build connecting pipelines 
to the Trans-Alaskan Pipeline. That line will be operating at 1.2 million 
barrels per day (mb/d) in early 1978 and that could later rise to 1.6 mb/d 
or ultimately to the design capacity of 2 mb/d. If additional quantities of 
crude oil become available in excess of that capacity, another distribution 
pipeline may be necessary. 



259 

It is much too early to speculate on the size and route of such a 
line since the need for it has yet to be proven, but there would be three 
basic routes which could be chosen. Two of these would be the same routes 
that were the subject of much heated debate prior to the selection of the 
current route of the Alyeska crude oil pipeline: the route from Prudhoe 
Bay to Valdez and the route from Prudhoe Bay through the MacKenzie Val- 
ley to Edmonton. Another pipeline along the current route would have the 
advantage of occupying the same right-of-way and sharing existing terminal 
facilities. The major disadvantage of that route is that even current pro- 
duction is in surplus on the West Coast and will be expensive to move to 
the Eastern United States. The MacKenzie Valley route would be longer and 
would cross Canadian territory, but it would not cross seismically active 
areas. The problem of native claims, however, would have to be settled. 
The proposed natural gas line from Alaska to the lower 48 States follows 
a third route which leaves the Alaska pipeline rights-of-way at Fairbanks 
and crosses British Columbia. The main advantage to either of the last two 
options is that they would deliver the oil to the Northern Tier Refiners 
who are in desperate need of feedstock because of the decision of the 
Canadian Government to halt exports of light crude oil by 1980. Most northern 
tier refineries cannot run arctic crude without costly retrofitting, how- 
ever, they utilize light Alberta crude. A renewed debate over pipeline 
routing must await the establishment of need for another major delivery 
system for Alaskan oil. Such a determination is probably at least a decade 
away. It does appear likely, however, that further North Slope discoveries 
will be made and will add considerable impetus to a revival of this issue. 



260 

3.2.3. Jones Act Issues * / 

3.2.3.1. Background . Cabotage laws refer to national laws requiring 
domestic waterborne cargo to be transported in domestic ships, 

v 

manned by domestic crews. Most countries have cabotage laws. In 

the United States, the word cabotage frequently is thought of 

2/ 

as another way of referring to the Jones Act, although: (1) cabotage 

laws were in effect in the United States long before the Jones 

Act was passed in 1920; (2) the Jones Act contained many provisions 

in addition to restoring the cabotage requirement on U.S. domestic 

waterborne traffic after the end of World War I; and (3) not all 

of the cabotage laws of the United States are contained in the 

Jones Act. Since the cost of U.S. ship construction and operation 

are higher than the cost of ships constructed elsewhere and manned 

by non-U. S. crews, the cabotage laws of the United States protect 

the domestic maritime industry from lower priced foreign ship 

competition. 

The cabotage laws of the United States include trade not only 
along the Pacific, Atlantic and Gulf coasts but also intercoastal trade 

*/ Prepared by Dr. Stephen J. Thompson, Analyst in Transportation, 
Economics Division. 

Ij The term cabotage means trade or navigation in coastal waters. 

2^/ The Jones Act is the popular name of the Merchant Marine Act of 
1920, 41 Stat. 988, 46 U.S.C. 883 (1970). 



261 



(between the coasts), and trade between the mainland and Alaska, Hawaii, 
Puerto Rico, and territories and possessions. The Virgin Islands, 
however, are exempt from U.S. cabotage laws. 

Cabotage has great impact on the transportation of Alaska North 
Slope oil (NS oil) for at least two reasons. First, it increases the 
transportation costs of NS oil as compared to the cost which would be 
incurred if the oil were carried in foreign flag ships. Second, the 
oil traffic would not be subject to the cabotage laws if the United 
States were to swap oil with Japan (or any other country) and conse- 
quently the United States maritime interests have been opposed to such 
a swap. One possible way of avoiding maritime opposition to a swap 
would be for Congress to allow a swap but require NS oil to be trans- 
ported to Japan in U.S. flag ships. President Carter discussed such 

an arrangement in his April 15, 1977 report to Congress on the pricing 

it/ 

of Alaska North Slope oil. 



2J The cabotage laws are not likely to result in a shortage of U.S. 

flag ships available to carry U.S. oil, according to the October 1976 
report by the Maritime Administration (MarAd), and later confirmed 
by industry sources, although it is expected that some ships that 
have received a construction subsidy will be needed; and in order 
to qualify, a portion of the construction subsidies must be repaid 
to the U.S. Treasury. (See the President's April 15, 1977 report, 
p. 36; and MarAd ' s October, 1976 report, p. vi.) 

hj The question of cabotage requirements for Alaska North Slope natural 
gas appears to be avoided entirely as a consequence of the recent 
decision to transport the gas along an all-land route in a pipeline 
to be constructed through Alaska and Canada to the lower 48 States. 
This decision was made by President Carter and approved by the Congress 
in House Joint Resolution 621, P.L. 95-158 which became law on Novem- 
ber 8, 1977. 

The 1973 rights-of-way legislation for constructing the Alaska 
pipeline (P.L. 93-153 (1973), 87 Stat. 576) required the President 
to pursue the possibility of constructing a second oil pipeline 
across Canada. That subject, however, apparently is not under active 
consideration by the Carter Administration. 



262 



A rough estimate of the impact of the Jones Act on the transporta- 
tion of NS oil can be computed by using the information in Table 1. It 
indicates that the cost might be in range of $76 million per year to 
the West Coast ($20 million from Valdez to Puget Sound and $56 million 
a year from Valdez to Long Beach); and $292 million per year to the 
Gulf Coast. It must be emphasized that these are not refined approxima- 
tions and that the figures are intended solely to give a rough benchmark 
of probable costs. Assuming that pipeline system from the West Coast 
comes on line, the impact of the cabotage laws will be significantly 
reduced . 

The Virgin Islands exemption from the cabotage laws is signifi- 
cant since one of the members of the consortium of companies which 
constructed and operates the Alaska pipeline, Amerada Hess, has sub- 
stantial crude oil refining capacity already installed on the Virgin 

TABLE 1 

IMPACT OF JONES ACT ON TRANSPORTATION COSTS OF ALASKAN OIL 

Quantity Amount 
U.S. flag Foreign flag Cost difference per year per year 

Route ($ per barrel) ($ per barrel) ($ per barrel) (million barrels)(million $ 



Valdez to Puget Sound 


.46 


.23 


.23 


85.2 


19.6 


Valdez to Long Beach 


.67 


.34 


.33 


170.3 


56.2 


Valdez to Gulf Coast via 
Panama Canal 


3.20 


1 .60 


1.60 


182.5 


292.0 



SOURCE: Based on the Federal Energy Administration (FEA) report entitled The Determination 

of Equitable Pricing..., pp. II-5 to III-13; FEA report entitled President's April 15, 
1977, Report to Congress..., pp. 24-27, 34-37; Cicchetti, pp. 108-115; Useem, pp. 
151-152; Maritime Administration (MarAd) 1976 report, pp. 6-16; and MarAd 1977 report, 
pp. 2-10. 



263 

Islands and there are some indications that Hess would like to refine 
Alaska oil at the Virgin Islands. (See the Maritime Administration 
(MarAd) October, 1977 report for a discussion.) In doing so, Hess could 
avoid the U.S. cabotage laws. The difference between the transportation 
costs using U.S. flag ships and foreign flag ships for NS oil to which 
Hess is entitled as a member of the consortium is shown in the second 
column from the right in Table 2. The last column on the right shows 
the larger volume of NS oil that the October, 1977 MarAd report estimates 
likely will be in excess of demand on the West Coast beginning in the 
spring of 1978 and which Hess might be in a position to handle. The 
potential reduction in transportation costs for oil transiting the 
Panama Canal to the Hess refinery in the Virgin Islands is estimated 
to be $15 million per year for the proportion of oil owned by Hess and 
$113 million per year for the estimated West Coast surplus that might 
be processed at the Virgin Islands and thus be exempt from the cabotage 
laws. As in Table 1, these figures are benchmark figures only. 



264 



TABLE 2 



COMPARISON OF TRANSPORTATION COSTS FROM VALDEZ TO VIRGIN ISLANDS 



Quantity per Amount per 
year (million year (million 
barrels) dollars) 



He s s He s s 

U.S. flag Foreign Flag Cost difference plus plus 

Route ($ per barrel) ($ per barrel) ($ per barrel) Hess 1/ others 2/ Hess 1/ others 2 / 

Via Panama Canal 3.20 .95 2.25 6.57 50.37 14.8 113.3 

Via a pipeline near 

Panama Canal 1.50 .67 .83 6.57 50.37 5.5 41.8 

Via Cape Horn 4.21 .72 3.49 6.57 50.37 22.9 175.8 



Via Panama Canal for 
U.S. flag and via 
Cape Horn for foreign 

flag 3.20 .72 2.48 6.57 50.37 16.3 124.9 



1/ Figures in this column refer to the proportion of NS oil that Hess is entitled to as a 
member of the pipeline consortium. 

2/ Figures in this column refer to Hess oil plus oil that MarAd estimated other consortium 
members might sell to Hess. 

SOURCE: Maritime Administration, 1977 report, pp. 2-10. 



265 

3.2.3.2. General Energy Policy Problems . The figures in Tables 1 and 
2 can be viewed from at least two perspectives. The first perspective is the 
one associated with the long established United States policy of providing 
assistance to the domestic maritime industry in the form of cabotage law protection 
from foreign ship competition. It is in this context that the 1977 Mari- 
time Administration report on Hess refining capability in the Virgin 
Islands concludes that: 

From the standpoint of protecting U.S. maritime interests, 
it would appear to be a propitious time to bring the Virgin Islands 
under the Jones Act. Naturally, as NS crude production increases 
over time, the amount that can be moved via foreign-flag tankers 
to the Virgin Islands can increase substantially if the Virgin 
Islands retain their present exempted status. 

From the viewpoint of consumers, the figures in Table 1 are the 
estimated costs to consumers on the transportation of oil from Alaska 
as a result of U.S. cabotage laws, and the figures in Table 2 are the 
estimated amounts that the Virgin Islands exemption from the cabotage 
laws will save consumers every year. 

The higher price of oil resulting from cabotage laws might be 
considered acceptable in order to encourage energy conservation, but, 
if so, there might be other ways to achieve the objective without pro- 
viding a direct benefit to only one industry in the economy. 

It should be noted that the taxes applicable to NS oil and to 
the corporations involved in NS oil production and pipeline transportation 

have been estimated to be more than half of any upward or downward shift 

11 

in wellhead price as a "result of higher tanker costs. Additional 
1/ Useem, p. 23. 



266 



considerations which might partially or completely offset the consumer 
cost aspects are the domestic employment, balance of payments, and 
national security aspects of cabotage protection for the U.S. maritime 
industry. Congress might wish to explore whether there are other ways 
to obtain the national security benefits, and whether domestic workers 
and capital which are presently engaged in the transportation of NS oil 
would be idle in the absence of the Jones Act, or whether they would 
be more efficiently employed in other industries. 



References 



Adelman, Morris Albert, Paul G. Bradley, and Charles A. Norman. 

Alaskan oil: costs and supply. New York, Praeger Publishers, 
1971. 127 p. 

Ciccetti, Charles J. Alaskan oil: alternative routes and markets. 
Baltimore, Maryland, Johns Hopkins University Press, 1972. 
142 p. 

Kilgour, John G. The cargo preference program and the cabotage restric- 
tion: effectiveness and cost. Transportation journal, spring 
1976, V. 15, no. 3, pp. 63-73. 

U.S. Congress. House. Committee on Interior and Insular Affairs. 

Oil and natural gas pipeline rights-of-way. (3 parts) Hearings 
before the Subcommittee on Public Lands on H.R. 9130. Washing- 
ton, U.S. Govt. Print. Off., 1973. Serial number 93-12. 93rd 
Congress, 1st session. 

U.S. Congress. Sentate. Committee on Energy and Natural Resources. 

Energy and Natural Resources. Alaskan oil price policy. Washing 
ton, U.S. Govt. Print. Off., 1977. Committee print, publication 
number 95-14, 95th Congress, 1st session. 284 p. 

U.S. Congress. Senate. Committee on Interior and Insular Affairs. 
Rights-of-way across Federal lands. (3 parts) Hearings on 
S. 1081 and other bills. Washington, U.S. Govt. Print. Off., 
1973. 93rd Congress, 1st session. 



267 



U.S. Department of Commerce. Maritime Administration. Foreign-flag 
tanker participation in North Slope crude trade. Washington, 
October, 1977. 10 p. 

The U.S. -flag tanker fleet and domestic carriage requirements; 

an assessment of fleet adequacy. Washington, October 21, 1976. 
68 p. 

This report is sometimes referred to as "the October report." 

U.S. Federal Energy Administration. The determination of equitable 
pricing levels for North Slope Alaskan crude oil. Washington, 
November 1976. Various pagings. 

This report is reprinted at pages 157-284 of the Senate Energy 
and Natural Resources committee print cited above. 

President's April 15, 1977, report to Congress on the pricing 

of Alaska North Slope (ANS) crude oil. Washington, 1977. 88 p. 

This report is reprinted at pages 35-124 of the Senate Energy 
and Natural Resources committee print cited above. 

Useem, Howard. Rate of return on investment in the Prudhoe Bay oil field 
of Alaska. Washington, Library of Congress, March 25, 1977. 
28 p. 

This report is reprinted at pages 125-156 of the Senate Energy 
and Natural Resources committee print cited above. 



268 

3.2.4. Transportation of Alaskan Coal *J 

Large coal reserves exist in Alaska, of good quality, for which 
demand may develop in export markets or conceivably along the U.S. West 
Coast. Although entirely hypothetical at present, such movements would 
require transportation capability not currently present. 

3.2.4.1. Transportation of Alaskan Coal — Background 

Alaska is the site of large reserves of low-sulfur coal, located 

primarily in the western part of the northern coastal region, but with 

large pockets of coal in various places in central and southern Alaska. 

Little is currently mined, but Alaskan coal sources may become important 

energy supplies to West Coast industries if the Alaskan oil surplus, now 

just beginning, is dissipated by distribution of oil to internal U.S. 

markets, and U.S. coal is preferred to foreign oil. In addition, a 

substantial export market may be developed to Japan, which now imports 

metallurgical coal from the U.S. East Coast. Although most Alaskan coal 

is not suitable for metallurgical purposes, it does constitute excellent 

steam coal, and some good coking coals have been discovered. 

In 1975, Alaska mines yielded 766,000 tons of coal, all from the 

Usibelli Coal Mines, a strip mine operation in the Nenana coal field. 

The coal was consumed primarily for production of electricity in Fair- 

1/ 

banks, at delivered costs of 33c per million Btu. 

Estimated resources of 19.4 billion tons of bituminous coal and 110.7 

2/ 

billion tons of subbituminous coal make up most of Alaska coal potential. 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 

1^/ 1976 Keystone Coal Industry Manual, p. 542. 

2/ U.S. Geological Survey estimate, 1972. 



269 



This would place Alaska fourth behind North Dakota, Montana, and Il- 
linois in coal resources among the States, but is an admittedly conservative 
estimate. Significant environmental problems would have to be overcome prior 
to mining of much of this coal, particularly that portion in the north 
Alaska permafrost area. This area contains 92% of the estimated resource. 

Southern Alaskan fields include the Susitna and Beluga fields, with 
strippable seams as much as 50 ft. thick under 120 feet of cover, and sul- 
fur content of less than one-fifth of one percent. Despite the adverse 
conditions under which mining takes place, the productivity of Alaska mines, 
at 35.52 tons per man-day, slightly exceeds the national average for surface 
mines . 

Transportation of coal mined in Alaska to markets is a critical de- 
terminant of the economics of Alaskan coal. The problems are different 
for the huge northern Alaska fields than for the various southern Alaska 
fields. Both will require overland movement of some sort to ship-loading 
points. For the northern Alaska fields, however, such transportation would 
be longer, in a more hostile and sensitive environment. Such ship loading 
points would be difficult to construct because of shallow water along the 

northern and northwest coasts, and difficult to maintain and use because 

4/ 

of icing conditions during much of the year. Hence the economics of 

moving such coal to market are questionable. 



_3/ 1976 Keystone Coal Industry Mannual, p. 542. 

4/ For an excellent discussion of the problems and possibilities of 

transporting north slope coal, see U.S. Congress, House of Representa- 
tives. Committee on Science and Technology, Subcommittee on Energy 
Research, Development, and Demonstrations. Polar Energy Resources 
Potential. (Prepared by the Congressional Research Service) 94th 
Cong. 2nd. Sess. Serial ZZ. September, 1976. 178 pp. @pp. 43-49. 
Much of this discussion is in turn drawn from Clark, P.R. Transportation 
Economics of Coal Resources of Northern Slope Coal Fields. Alaska, 
M.I.R.L. Report No. 30. Univ. of Alaska, Fairbanks, 1973, 134 pp. 



270 

Nonetheless, one study suggests that North Slope coal up to 200 miles 

from a harbor could be moved to the water and shipped to Japan at a delivered 

price of less than $10.00 per ton, if there were 15,000,000 tons per 
5/ 

year mined. 

The situation for southern Alaska fields is substantially different. 
The Susitna and Beluga coal fields, as well as the subbituminous fields of 
the Kenai peninsula, are directly located on the deep water Cook Inlet 
near Anchorage, which is relatively ice free. Standard conveyors or 
loading systems could presumably be used to put coal onto the ships virtual- 
ly directly from the mines. According to Cleland Conwell, of the State 
of Alaska Geological Survey, writing in the Keystone Coal Industry Manual, 

"The new super cargo carrier and loading techniques should make a coal 

6/ 

mine near tidewater competitive anywhere in the world." Plans were 
announced in February 1978, for a ship loading dock at the Beluga coal field. 

For coal fields too far inland for conveyor belts or other minemouth 
loading devices, the Alaska Railway's lines run to Fairbanks near some 
of the major coal deposits, where spur lines could be possible, or con- 
veyors could run to train loading stations. The Nenana fields, containing 
457 million tons, and other potential coal deposits are near the right 
of way. In addition, it has been suggested that the Alaska railway could 
conceivably be extended north to the north slope coal fields, although 
problems of keeping the track open in the winter and building environmentally 



5j Op. Cit. Clark, quoted in Op. Cit. Committee on Science and Technology, 
p. 43. 

Op. Cit. Keystone , p. 542. 



271 

acceptable right-of-way might prove severe, and the economics insurmountable 

7/ 

without other traffic besides coal. 

Coal mine development in Alaska almost invariably requires State or 
Federal permits or coal leases, and many of the likely coal sites are 
contained in the lands proposed for withdrawal as D-2 lands or under other 
designations. Congressional action would probably be required to permit 
mining of some of the involved lands or to transport the coal overland once 
mined. It may be years before the coal lease availability question is resolved. 

3.2.4.2. Analysis . General energy policy questions involved in 
the question of transporting Alaskan coal include the question of the 
desired forms of energy for consumption on the West Coast of the U.S., . 
the only likely domestic market besides Alaska itself. Maintenance of 
air quality requires a clean fuel, and Alaskan coal is very low in sulfur 
content whether measured by weight or per million Btu's consumed. With 
the West Coast surplus of Alaskan oil currently growing based on deliveries 
from Valdez, Alaskan coal is not being looked to as a possible fuel, 
even though the oil is fairly high in sulfur content. A situation can 
be envisioned in a few years, however, when systems are in place to 
move Alaskan oil to other inland oil consumers, when West Coast demand 
for Alaskan coal might arise. Large industrial installation may be required 
or encouraged to convert to coalin order to free Alaskan oil for purposes 
coal cannot satisfy elsewhere in the U.S., or to restrain overall oil 
imports. Another possible market may be found among electric power generators 
in the Pacific Northwest, where hydroelectric capacity may need to be 
supplemented with steam power plants over the next few years. 

7/ Op. Cit. Committee on Science and Technology, p. 48. 



272 

If that occurs, coal from Alaska may compete with coal moved overland 
from the large deposits across the Rocky Mountains in the Northern Great 
Plains. Slurry pipelines to move Great Plains coal to the' Pacific 
Northwest are being actively considered ( See Map no. 2, Volume 1). Unit 
train rail movements are also feasible — the distances involved are 
not greater than some of the unit train movements currently being made 
in an eastward direction from Wyoming fields. 

The cost of maritime coal movement is generally lower per ton than 
that of slurry pipelines or unit trains. The requirement of Jones Act 
vessels to move coal from Alaska to the West Coast would, however, increase 
the costs above those of shipments to Japan or elsewhere. The cost per 
ton of coal delivered to a West Coast port city such as San Francisco 
or Los Angeles from Alaska by ship, versus coal from the Northern Great Plains 
by unit train, may, however, be within the range of competition. Alaskan 
coal would be unlikely to be competitive with Western coal elsewhere 
in the United States. 

Because of the uncertainty of demand for coal along the Pacific Coast, 
the uncertainty of lease availability in Alaska for coal mining, the current 
lack of U.S. -flag and U.S.-crewed coal carriers on the West Coast, or 
elesewhere for that matter, and the unestablished economics of coal 
delivery to the West Coast from midwest fields, the domestic movement of 
Alaskan coal is also uncertain and clearly years away at best. Mining and port 
facilities would probably first be constructed to serve export markets, 
in any case. Nevertheless, the currently identified resources of coal 
in Alaska, conservatively estimated, are almost six times the energy 
equivalent of the most generous U.S.G.S. estimate of the potential oil 



273 

and gas resources in the State. With such an amount of energy conceivably 
available, it is appropriate to consider early some of its potential 
problems, markets, and means of transportation. 



24-786 O - 78 - 19 



274 

3.2.5. Alaska Pipeline Rates and Tariffs * / 

The oil companies who own the Alyeska pipeline or Trans Alaska 
Pipeline System (TAPS) are currently engaged in a proceeding before the 
Interstate Commerce Commission over the propriety of the rates they propose 
to charge. Because they are also the owners of the oil field which will 
feed the pipeline, higher pipeline tariffs do not reduce their overall 
receipts for crude oil by lowering the effective wellhead price. Higher 
tariffs do, however, reduce their tax liability and royalty obligations to 
the State of Alaska, which are based on the wellhead value. The tariff 
treatment of the pipeline may also affect the further development of Alaskan 
oil resources by providing different incentives to owner and non-owner 
companies . 

3.2.5.1. Introduction . On June 28, 1977, just eight days after 
Prudhoe Bay oil began to flow, the Interstate Commerce Commission (ICC) suspended 
the initial rate filings of the eight Trans Alaska Pipeline System (TAPS) 
owners and established a set of lower interim rates to be used until its rate 
investigation is completed. Following the rejection by the Fifth Circuit 
Court of Appeals of a Mobil Oil Corporation request for a temporary restraining 
order against the ICC ruling, all eight companies filed the interim rates 
authorized by the ICC; if they had not filed they would not have been able 
to transport crude oil. The companies then appealed the ICC decision to the 
Supreme Court and were granted a stay of the ICC-ordered tariff until the 
Court could hear the appeal. The Court has not yet ruled. 

While the primary issue in the TAPS tariff case is the deter- 
mination of those tariff rates which provide a fair and equitable rate 

*/ Prepared by Howard Useem, Analyst, Economics Division. 



275 



of return to the TAPS owners, the decision will necessarily affect the 
revenues which the State of Alaska collects from the Prudhoe Bay field, 
and it may impact on the future development of other Alaskan petroleum 
fields . 

3.2.5.2. Background . TAPS is a 48 inch diameter crude oil pipeline 
which extends 800 miles from the Prudhoe Bay oil field which is located 
on the northern coast of Alaska, to Valdez, an ice-free deepwater port 
located on Alaska's Southern coast. When fully operational, TAPS is 
presently designed for transporting 1.2 million barrels of crude oil 
per day (MMBbl/D). If field production warrants, TAPS throughput capacity 
can be raised to 2.0 MMBbl/D by adding more pump stations. As a result 
of the July 1977 fire in pump station 8, throughput is currently limited 
to about 715 MBbl/D. Pump station 8 is expected to be back in operation 
by the end of March 1978 at which time throughput is expected to rise 
to 1.2 MMBbl/D. 

1/ 

Eight companies have an undivided interest in TAPS. These 
companies and their percentage ownership are: 



Sohio Pipeline Co. 


33 


.34% 


Arco Pipe Line Co. 


21 


.00 


Exxon Pipeline Co. 


20 


.00 


BP Pipelines Inc. 


15 


.84 


Mobil Alaska Pipeline Co. 


5 


.00 


Phillips Alaska Pipeline Corp. 


1 


.66 


Union Alaska Pipeline Co. 


1 


.66 


Amerada Hess Pipeline Corp. 


1 


.50 



\J The undivided ownership form means that each pipeline owner operates 
its share as if it were a separate pipeline. Each owner separately 
publishes a tariff schedule and receives tenders for shipments through 
its share of the pipeline. Generally speaking, construction and 
maintenance expenses are prorated according to the percent share 
of ownership and operating expenses are charged in relation to each 
company's throughput. 



276 



Generally speaking, the same companies that own TAPS own the Prudhoe Bay 
field. The percent ownership of Prudhoe Bay oil production is: 



Sohio/BP 53.16 

Arco 20.27 

Exxon 20.27 

Mobil 2.12 

Philips 2.07 

Chevron .79 

Getty .55 

Amerada Hess .54 

Marathon .05 

LL&E .04 

Placid .04 

N.B. Hunt .03 

Hunt Industries .02 

Caroline Hunt Trust .02 

Wm. Herbert Hunt .02 

Lamar Hunt .02 



(May not total 100.0 percent due to rounding.) 
SOURCE: Oil and Gas Journal, April 4, 1977: p. 57. 



3.2.5.3. The TAPS Tariff Controversy . The ICC's June 28th decision 

to suspend the initial TAPS owner's tariff filings was in part based on 

its conclusion that there was some question as to the accuracy of the data 

II 

submitted by the companies in support of their filings. The ICC found the 

assumed rate of depreciation and the data associated with the anticipated 
cost of the removal of the line particularly troublesome. In its decision 
the ICC stated that: 



2/ Interstate Commerce Commission. Investigation and Suspension Docket 
~ No. 9164. Trans Alaska Pipeline System. June 28, 1977. 



3/ Id. at 5. 



277 



Some of the carriers propose to simply set aside one twenty- 
fifth of their total share of ... [pipeline removal costs] each 
year for 25 years. Others propose more detailed computations 
to inflate the removal costs to dollar costs for the year 2002, 
and to allow for compound interest on the yearly accruals. The 
protestants, on the other hand, seek to reduce the yearly removal 
charges by requiring that they be amortized over a period longer 
than 25 years. 

With respect to depreciation charges, the carriers uniformly 
propose a 25-year service life, on the basis that known recoverable 
reserves on the North Slope are expected to be depleted in terms 
of economic recovery in 25 years. Protestants propose that service 
lives as long as 35 years be required, on the basis that addi- 
tional oil fields exist on the North Slope that are likely to 
extend the pipeline's useful life and that even the present 
reserve may have a longer life than 25 years. 

The ICC also questioned the method which the TAPS owners employed 

in their determination of the allowable tariff and their treatment of 

interest costs. Despite their reservations about the companies' cost 

data, in using it the ICC still concluded that the method by which the 

companies calculated their tariffs may have led to an excessive rate of 

it/ 

return. The ICC stated in its decision that: 

In justifying the filed tariff rates, the carriers contend 
that the proposed rates are merely sufficient to cover expenses 
and interest and to allow an after-tax return on equity equal 
to 7 percent of their valuation. They consider this method of 
gauging a return on equity to be permissible since it is used 
in the 1941 consent agreement between the Justice Department 
and a large number of shipper-owned pipelines. 

However, the consent decree standard has never been employed 
in a Commission proceeding as the test of reasonableness of rates. 
Its sole legal status is as a limit on the amount of dividends 
that pipelines may pay to shipper owners without risking prosecution 



4/ Id. at 6. 



278 



under the Elkins Act for illegal rebates. Moreover, as a standar 
of reasonableness, it has nothing to recommend it from a concep- 
tual standpoint. Although valuation is a measure of the entire 
investment, the consent decree standard allows a return on 
valuation to be used entirely to compensate one segment of the 
capital invested. Such a standard can have no relationship, 
except by coincidence, to the carriers' true capital costs. As 
shown in Appendix 3, the filed rates would produce returns on 
equity ranging from 31 percent to 96 percent. Even if the car- 
riers had a lower capital structure of 60 percent debt and 40 
percent equity, the proposed rates would provide returns on equit 
ranging between 16.8 percent and 20.6 percent. The Department 
of Justice suggests 14 percent as a suitable number for use as 
the cost of equity capital at this stage of the proceeding. We 
agree that this would be a suitable figure for present purposes. 
Accordingly, it can be seen that the filed tariff rates would 
produce returns exceeding capital costs, even where the carriers' 
own expense and investment data are accepted. 

Pending the outcome of its full rate investigation, the ICC 

calculated interim tariffs which would provide a 10 percent rate of 

return on the rate base using the TAPS owners ' cost data. As can be 

seen from the table below, the ICC rates are 19 percent to 26 percent 

lower than those asked by the TAPS owners, but still greater than those 

recommended by the Department of Justice, the State of Alaska, and the 

ice's own staff. The ICC calculated that these tariffs would provide 



Proposed for TAPS Tariffs 









State of 


ICC 


Dept. of 


ICC's 




% owner- 


Carrier 


Alaska's 


staff's 


Justice 


interim 


Company 


ship 


filings 


filings 


filings 


filings 


tariff 


ARCO 


21.0 


6.04 


3.74 


4.85 


4.40 


4.91 


Union 


1.66 


6.09 


3.85 


4.99 




4.89 


Sohio 


33.34 


6.16 


4.04 


4.54 


4.54 


4.70 


Exxon 


20.0 


6.27 


3.80 


5.00 


4.19 


5.10 


Mobil 


5.0 


6.31 


3.59 


4.80 


4.53 


4.84 


BP 


15.84 


6.35 


4.42 


4.59 


4.53 


4.68 


Amerada-Hess 


. 1.5 


6.44 




4.60 


4.58 


4.85 


Phillips 


1.66 


6.22 











SOURCE: Oil and Gas Journal. 



279 

5/ 

the TAPS owners with a return on equity ranging from 13.3 percent 
to 54.3 percent, depending on the individual company's capital 
structure. 

Following the ICC decision, Mobil Oil sought a temporary restraining 
order from the Fifth Circuit Court of Appeals to prevent the ICC from 
establishing the lower interim rates. Mobil argued that the ICC had 
exceeded its authority by establishing tariff rates without a full rate 
proceeding. Mobil also argued that since by law undercharges cannot 
be recouped at a later date through increased tariffs, the ICC's decision 

to require lower interim rates would result in an unrecoverable loss 

7/ 

if it were later determined that the higher rates were justified. 
Moreover, Mobil noted that if the full rate investigation did conclude 
that the lower tariffs were appropriate, the ICC could order a retro- 
active rebate of the overcharges with accrued interest. The Fifth 
Circuit Court of Appeals denied Mobil's request, ruling that the ICC 
had acted properly. All of the owner companies have appealed to the 
Supreme Court and have been granted a stay of the ICC tariff pending 
a review of their appeals. 

_5/ It is not possible to calculate a rate of return on equity for Mobil 
since its share of TAPS was totally debt financed. 

6/ ICC at 7. 

Ij Mobil calculated that the lower interim rates would reduce TAPS 

owners' income by $343 million over the seven-month interim period. 
(Source: Oil and Gas Journal, July 11, 1977: p. 37.) 



280 

The State of Alaska has, of course, a considerable financial 

interest in the outcome of the TAPS tariff case. The State has a 12.5 

percent petroleum royalty, a 12.25 percent severance tax on oil, a 

9.4 percent corporate income tax, a 20 mill oil and gas property tax, 

a 20 mill oil and gas reserves tax, a regulation and conservation 

tax of 1/8 of 1 cent per barrel of oil removed or sold, and a 1 percent 

disaster tax on production. In addition, Alaska enjoys a 90/10 percent 

split on all rental and royalty income on Federal lands in the State. 

Thus, for every 1 dollar reduction in the TAPS tariff, the pre-tax 

wellhead price of Prudhoe oil will rise by a like amount and the State 

of Alaska will gain roughly 25 cents. At 720 MBbl/D, the ICC interim 

tariffs (which average approximately $1.40 less than the companies' 

requested tariffs) results in about an additional $252,000 per day or 

10/ 

revenues to the State of Alaska. At full capacity of 2 MMBbl/d they 

result in additional State revenues of $700,000 per day. 



3.2.5.4. Additional Questions . It is not entirely clear the extent 
to which the TAPS tariff will affect the future development of other 
Alaskan petroleum resources. For those tracts which have yet to be leased. 



8^/ Of the 12.5 percent royalty (which can be taken in kind), 2 percent 
is to be paid into the U.S. Treasury for the Alaska Native Fund until 
the fund amounts to $500 million. 

^/ Applies only in 1976 and 1977. 

10/ 720MBbl/D x .25 x $K4 = $252 ,000/day . 



n/ 2 MMBbl/d X .25 x $1.4 = $700 ,000/day . 



281 

if the purchaser is a TAPS owner, a higher tariff would reduce its overall 
State tax liability and therefore may result in either a higher overall 
rate of return or a higher winning bonus bid. If the tract purchaser 
is not a TAPS owner, a higher tariff would reduce the wellhead netback 
and therefore may result in either a lower rate of return or a lower 
winning bonus bid. The degree to which either outcome will occur will 
depend on the elasticity of demand for Alaskan petroleum properties, 
something of which little is known. 

For the Lisburne and Kuparuk fields which are adjacent to the 
Prudhoe BAy field, a reduction in the TAPS tariff may reduce the incen- 
tive to the owners to develop these fields. Since the owners of these 
fields are, to a large extent, the same as the owners of TAPS as noted 
earlier, a lower TAPS tariff would reduce the owner's net income by 
increasing its State of Alaska tax liability. For other fields, if 
ownership is substantially different from TAPS ownership, then a tariff 
reduction would encourage field development. 

It should be kept in mind that the TAPS tariff is but one factor 
which affects the wellhead price of Alaskan petroleum. And in the long 
run, factors such as entitlements, tanker shipping costs, OPEC oil pricing 
policies, domestic crude oil price regulations, and field production costs 
may have a far greater impact on the development of Alaskan petroleum, 
and oil company and State of Alaska revenues than the final outcome of 
the TAPS tariff case. 

3.2.5.5. Intrastate Rate Questions . A separate rate controversy has 
emerged concerning the delivery of oil through the TAP's pipeline to a 



282 

refinery located at North Pole, Alaska, near Fairbanks. The Alaska 
Pipeline Commission is to rule on the question of what rate the refinery 
owner should pay to the owners of the TAPS line for this intrastate oil 
movement. In hearings which concluded January 9, 1978, the pipeline 
owners testified that a rate equal to that for deliveries all the way 
to Valdez was proper, even though the distance the oil moved to North 
Pole was only 58% of the total distance to Valdez. Their reasoning was 
that the 20,000 barrels per day taken out of the pipeline at North Pole 
would reduce the capacity of the line all the way to Valdez because no 
other oil is available to ship. The Pipeline Commission has set interim 
tariffs which are 58% of the total rates of $6.04 to $6.44 per barrel, 
based on the distance. A final ruling is expecting in the Spring. 



283 



3.2.6. The Alaska Natural Gas Transportation Issue * / 

Issue Definition. The shortage of natural gas in the United States 
has manifested itself in shrinking proven reserves, declining production 
levels, and increasing curtailments of natural gas usage. Hopes to al- 
leviate some of the natural gas shortage rest with the substantial natural 
gas reserves in Alaska. Three proposals to transport Alaskan natural gas 
to the lower 48 States were considered, and on September 8, 1977, President 
Carter and Canadian Prime Minister Trudeau announced jointly that they had 
selected Alcan's Trans-Canadian route. Legislation approving the route 
selection was passed by the U.S. Congress, and signed into law on November 
8, 1977. The Alcan project, renamed the Alaskan Highway Gas Pipeline, will 
cost between $10-$15 billion making it the most expensivee private sector 
undertaking in history. Sponsors of the project have maintained, and the 
President has concurred that financing the giant pipeline can be done 
entirely in the private money markets without Government assistance. Presently 
it is too early to tell if the project will be able to secure financing 
on its own, but herein lies the main issue that may warrant future congressional 
attention: if the Alcan project cannot find sufficient financing, the 
Congress could be faced with authorizing Federal assistance in order to 
insure complete financing of the project. 

3.2.6.1. Background . In 1968, natural gas was discovered at Prudhoe Bay 
on the North Slope of Alaska with the field estimated to contain 26 tril- 
lion cubic feet (tcf) of proven natural gas reserves or an amount greater 
than 10 percent of total U.S. reserves. Some experts think the total 

*/ Prepared by Gary J. Pagliano, Analyst, Environment and Natural Resources 
Policy Division. 



284 

potential recoverable resources could run as high as 72 to 185 tcf. The 
discovery of natural gas in Alaska comes at a time when the lower 48 States 
are experiencing a severe natural gas shortage. The lack of new gas dedi- 
cations to the interstate market along with a general decline in gas production 
had led the Federal Power Commission (FPC) to project a 3.9 tcf supply 
deficiency for firm customers during April 1977 through March 1978. Worse 
shortages are expected in the future. 

The Alaskan natural gas supply could alleviate a significant portion 
of the U.S. shortage by potentially supplying as much as 1.2 tcf annually, 
as soon as the delivery system is completed. 

Three major proposals to transport Alaskan natural gas to the lower 
48 States were submitted to the Federal Power Commission (FPC), now part 
of the Department of Energy (DOE). They included the Arctic Gas and Alcan 
all-pipeline projects which called for transporting Prudhoe Bay and Canadian 
natural gas through Canada to Canadian and U.S. markets. The Arctic Gas 
pipeline would have traversed the northwest territories, following the 
Mackenzie River, and then divided in the northwest territories, one branch 
going West to California and the other East to Illinois. The Alcan pipeline 
route would have parallelled the Trans-Alaska Oil Pipeline, followed the Alaska 
Highway through Canada, and also divided, sending natural gas West to 
California and East to Midwestern and Eastern markets. The other proposal, 
submitted by El Paso, would have been a combined pipeline-liquefied natural 
gas (LNG) system following the Trans-Alaska Oil Pipeline corridor to 
a coastal LNG plant where refrigerated tankers would have transported the LNG 
from Alaska to California and a planned link up to the national distribution 
system. [See Figure I for mapped routes]. 



285 



Figure I 




Possible Pipeline Routes for Northern Gas 



— _ Mackenzie Valley Route 

(Arctic Gas or Foothills) and 
Connections in Canada 

• ••••••• Prudhoe Bay to Mackenzie Delta 

Route (Arctic Gas) 

— — _ Alaska Highway Rout* 
(Alcan Project) and 
Connections in Canada 



TransCanada Pipelines, taking 
Mackenzie Delta Gas to 
Eastern Canada 

Connecting Pipelines in the 
United States 

El Paso Route (Pipeline and 
Tanker System) 

National Energy Board 
preferred route 



286 

The U.S. and Canada each set up a regulatory process by which to 
evaluate the Alaskan natural gas transportation alternatives. In the 
U.S., the regulatory process was formally legislated in the Alaskan Natural 
Gas Transportation Act (P.L. 94-586). The Act required the FPC to re- 
commend a transportation system to the President by May 1, 1977. Other 
Federal agencies, State Governors, and interested parties then had 
until July 1, 1977, to submit comments to the President on the FPC's re- 
commendations. Also, by that date, the Council on Environmental Quality 
was to give the President a report on the adequacy of each transportation 
proposal's environmental impact statement. By September 1977, the President 
was to propose to the Congress a natural gas transportation system, which 
the Congress would then have to approve by a joint resolution. 

3.2.6.2. The Agency Studies. On May 1, 1977, the FPC recommended 
an overland Trans-Canadian pipeline route to bring Alaskan gas to the lower 
48 States, but stopped short of selecting either the Arctic Gas or the 
Alcan proposal. The FPC found the overland routes offered lower-priced 
delivered gas, more economic pipeline capacity expansion, less environmental 
impact, and greater reliability and safety. The third proposal, the El 
Paso proposal, was found however, to have the most feasible financing 
scheme primarily based on its LNG tankers qualifying for Federal Government 
financial guarantees under Title XI of the Merchant Marine Act of 1936. 
The recommendation stressed, though, that the Canadian Government still 
had to express its intentions on the Canadian portions of the proposed 
overland routes before any meaningful decision could be made on the proposals. 



287 

Two months later, a group of U.S. Interagency Task Force and the 
Council on Environmental Quality (CEQ) reported on the alternatives for 
transporting Alaskan natural gas. The CEQ pointed out that while there 
would be some environmental destruction associated with all three of the 
proposals, the degree of destruction would vary with each proposal. The 
Arctic Gas proposal was judged the most environmentally damaging of the 
three mainly because of its intrusion into the pristine wilderness 
stretching from Alaska's Canning River to Canada's MacKenzie Delta. 
Although not as destructive as the Arctic proposal, El Paso's pipe- 
line would mean significant harm to the Chugach National Forest, and 
the project's cooling tower at the Point Gravina liquefaction facility 
would mean destruction of marine life in Orca Bay. As a result, CEQ 
concluded the Alcan proposal was the least environmentally damaging 
alternative, but its conclusion assumed a strict adherence to environ- 
mental concerns during the pipeline's design and construction. 

The Interagency Task Force reports similarly favored the Alcan pro- 
posal. Led by the Federal Energy Administration, a task force consisting 
of Treasury, Labor, and Commerce Departments, the Office of Management 
and Budget, and the Council of Economic Advisors concluded Alcan would 
produce the highest economic net benefits to the U.S. Another task force 
led by the Interior Department said Alcan posed the least environmental 
impact. And still another task force led by the Transportation Department 
stated the efficiency of the Alcan system would be higher than the El Paso 
proposal because evidence showed El Paso would consume 11 to 12 percent 
of the natural gas transported within its system while the Alcan would 
only use 7 percent. 



288 

3.2.6.3. Canada ' s Decision. The first sign of Canadian intentions 
came from a special commission called the Berger Commission, set up to 
evaluate the socio-economic and environmental impact of the Arctic Gas 
pipeline segment running across Canada's Northern Yukon area to the Mackenzie 
River Delta. The Berger Commission recommended against any northern Yukon 
pipeline because of its potentially harmful environmental impact. The 
Commission also found it was environmentally acceptable to build a pipeline 
along the Mackenzie Delta, but should be postponed for 10 years to allow 
sufficient time for settling the native claims issue. Finally, it concluded 
the most environmentally preferable pipeline route carrying Alaskan natural 
gas to U.S. markets was along the Alcan Highway crossing the southern 
Yukon . 

Canada's most far reaching decision came when its National Energy 
Board (NEB) conditionally approved the Alcan proposal but with some modi- 
fication in its route. The modification would mean diverting the northern 
Canadian portion of the pipeline eastward to Dawson City in the Yukon, 
thereby facilitating a possible future linkup between the pipeline and gas 
fields in Canada's Mackenzie Delta region. The pipeline modification was 
one of three main conditions set by the NEB for pipeline certification; 
the other two were: (1) the Canadian Government would have voting control 
of the equity in each pipeline company operating the Canadian portion 
of the pipeline, and (2) the pipeline sponsors would provide up to $200 
million to the Canadian Government to pay for indirect social and economic 
costs causes by the pipeline north of the 60th parallel. 

The NEB decision was important because it left the Alcan and El Paso 
proposals as the only choices open to the President and the Congress. Also, 



289 , ■ 

the neb's conditions would add about $700 million to Mean's total cost, or 
about 6 cents to the cost of each thousand cubic feet of Alaska gas con- 
sumed in the U.S., thus making the El Paso proposal more competitive with 
the previously cheaper Alcan proposal. 

3.2.6.4. The Joint Decision . Soon after the NEB decision, the Carter 
Administration announced it was opposed to the change in route and the 
$200 million extra charge. Negotiations ensued to work out a compromise 
and on September 8, 1977, President Carter and Canadian Prime Minister 
Trudeau announced jointly that they had selected the Alcan route for transporting 
Alaskan natural gas to the lower 48 States. In the agreement, Canada's demand 
for a $200 million fund to offset the social and economic impact of the 
pipeline on Canadian citizens was structured as a loan from the pipeline 
company to be repaid through reducing its future property-tax liability. 
Canada dropped its demand for the 125-mile diversion, but in exchange, 
the U.S. agreed to share the cost of a possible future Alcan-Mackenzie 
Delta pipeline. The agreement also provided for rapid construction of 
the Alcan pipeline segment running from Alberta's recently discovered 
gas fields to the natural gas hungry Midwest. The construction would enable 
the U.S. to receive, possibly within two years, 800 million cubic feet 
of gas per day which the U.S. would repay with future Alaskan gas deliveries. 

The U.S. Congress passed a joint resolution approving the Alcan pro- 
posal and on November 8, 1977, the legislation was signed into Public Law 
95-158. Once the agreement was made law, the Alaska Natural Gas Transporta- 
tion Act of 1976 served to minimize potential regulatory delays in the 
U.S. by limiting the judicial review process associated with route decision. 

24-786 O - 78 - 20 



290 

In Canada, the Parliament has begun work on legislating the agreement. 
The current thinking is, that since the Prime Minister and his Cabinet have 
endorsed the agreement, the Parliament will act as favorably and expeditiously 
as possible. 

As a show of cooperation, the U.S. and Canada have already ratified 
a treaty which covers all existing and future U . S .-Canadian gas as well 
as oil pipelines (see 3.3.11). The U.S. -Canada Transit Pipeline Agreement, 
ratified by the Senate on August 3, 1977, provides three basic protections 
for the pipelines: (1) protection against interference with the flow of 
hydrocarbons in transit; (2) assurance of "in bound" treatment of hydrocarbons 
in transit and (3) protection against discriminatory taxation by public 
authorities in either country. Although the treaty applies to all pipelines, 
the original intent of the treaty was to insure than an Alaskan gas pipeline 
through Canada would neither be subject to discriminatory provincial taxes 
nor to interruptions of its gas supplies flowing to American markets. 

3.2.6.5. Distribution . The Alcan proposal calls for delivering 2 billion 
cubic feet per day (bcfd) of Alaskan natural gas by 1983 to the lower 
48 States and 2.4 bcfd within a few years, after '83. Just before the 
Alcan pipeline reaches the lower 48 States, it divides into an eastern 
leg which will service the U.S. Midwest and East, and most likely into 
a western leg which will service the U.S. Northwest and California. 

Alcan' s plans to build the eastern leg are straightforward because 
there is no other feasible way to deliver the gas. The eastern leg will 
deliver about 70 percent of the Alaskan gas to the Midwestern and Eastern 
markets. It will begin at James River, Alberta, cross Alberta, Saskatchewan, 



291 

Montana, North Dakota, South Dakota, Minnesota, Iowa and terminate at 
Dwight , Illinois (near Chicago). It will be 1,352 miles including 235 miles 
in Canada and 1,117 miles in the U.S. (see Figure 2). Once the Alaska 
gas reaches the Saskatchewan/Montana border, it is transferred from the 
Canadian-owned portion of the Mean system to the Northern Border Pipeline 
system, a consortium of six U.S. natural gas pipeline companies: Northern 
Natural Gas Company, Michigan-Wisconsin Pipe Line Company, Natural Gas 
Pipeline Company of America, Panhandle Eastern Pipe Line Company, Texas 
Eastern Gas Transmission Corporation and Columbia Gas Transmission Corporation. 
The Northern Border Pipeline will deliver gas directly to Natural Gas 
Pipeline, Northern Natural Gas and Michigan-Wisconsin, while the other 
members of the consortium will receive Alaskan gas by displacement. Displace- 
ment means that Alaskan gas will be supplied to a pipeline company which 
is physically closer to the Alcan pipeline in exchange for other gas delivered 
to the original Alaskan gas consortium member elsewhere. The specific 
quantities of gas going to each pipeline will be determined when gas sale 
contracts are executed. 

3.2.6.6. The Western Leg Issue. There are two feasible ways to deliver 
about 30 percent of the Alaska gas to the Northwest and Californian markets. 
The first is a displacement option which involves delivering the Western 
share of the Alaskan gas to the Midwest through an expanded Northern Border 
Pipeline. In exchange, natural gas from West Texas and New Mexico that 
otherwise would flow to the Midwest would then be diverted to the West 
Coast through the El Paso and Transwestern pipeline systems. The second 
alternative is to construct a western leg to the Alcan system involving 
some entirely new pipeline and some "looping" pipeline in Canada 
from Caroline Junction to Kingsgate, and then increasing U.S. pipeline 



292 



Figure 2 




293 

capacity also through "looping" the existing Pacific Gas Transmission 
Company (PGT) and Pacific Gas and Electric Company (PG & E) pipeline sys- 
tem. Looping occurs when a pipeline is built parallel to an existing 
pipeline expanding its capacity and utilizing existing regulatory permits 
and mechanical facilities. The President's Decision and Report to Congress 
on the Alaska Natural Gas Transportation System (President's Decision 
and Report) estimates a fully looped system would cost about $770 million 
(1975 dollars) versus $260-$400 million for increasing the capacity of 
the Northern Border System. In addition, the cost of service for the 
displacement plan would be $50 million per year less than direct delivery 
plan. 

At first glance, the displacement plan looks clearly superior, but 
closer examination shows the plan has a potential negative impact on other 
aspects of U.S. natural gas supply policy. First, the displacement* plan 
would consume more energy than direct delivery to the West because of the 
markedly greater transportation distances the Alaskan gas would have to go. 
In comparison, the looping of the PGT and PG & E systems would increase 
the overall energy transportion efficiency of those systems. The President's 
Decision and Report estimates the looped system would save 25 billion cubic 
feet of gas per year worth $68 million because of transportation efficiencies. 

Second, the natural gas diverted to the West Coast because of the 
displacement plan could overload the existing pipeline capacity in the 
Southwestern part of the U.S. Presently, the West is supplied with most 
of its natural gas about 4.9 billion cubic feet per day(bcfd) via interstate 
pipeline from two major producing areas — 3.5 bcfd comes from the Permian 



294 

and San Juan Basins in Texas and New Mexico, and 1.4 bcfd comes from the 
Alberta and British Columbia reserves in Canada. Only two pipeline systems, 
the El Paso and Transwestern systems, deliver natural gas from the Permian 
and San Juan Basins to California, Arizona and New Mexico. Total capacity 
of the El Paso and Transwestern systems (sometimes called the Southwest 
system) is approximately 4.6 bcfd, more than adequate to accommodate current 
gas deliveries of 3.5. bcfd and the projected .7 bcfd of displaced Alaskan 
gas . 

However, there are other natural gas supply factors to consider. First 
one of the El Paso pipelines in the Southwest will most likely be converted 
to an oil pipeline as part of Sohio's effort to transport economically, the 
excess Alaskan oil to the Midwestern and Eastern markets. The loss of one 
El Paso pipeline will leave the southwestern system with a 4.0 bcfd capacity 

Second, new potential gas supplies would need to utilize the southwest 
pipeline system. Substantial volumes of Mexican natural gas could become 
available for transportation to the West Coast (see 3.5.14). Petroleos 
Mexicanas (Pemex), the government-controlled oil and gas corporation in 
Mexico, has announced its intent to construct a pipeline from the Reform 
fields in Chiapas and Tabasco to the U.S. border near McAllen, Texas. 
If the plan goes through the pipeline would deliver 1 bcfd in 1980 and 
2 bcfd by 1982 and the West's share of the Pemex gas would be about .4 bcfd. 

Third, El Paso has an application before the Federal Energy Regulatory 
Commission (FERC) for the so-called Algeria II project which would deliver 
up to .33 bcfd of regasified liquefied natural gas (LNG), from the Texas 
Gulf Coast to the Southwest by as early as 1983, and could deliver .65 
bcfd by the following year. 



295 



Finally, the Wesco coal gasification project in the Southwest 's Four 
Corners area should begin gas deliveries, which some estimate could be 
as high as .28 bcfd by 1987. The Wesco coal gas will be delivered by Trans- 
western. The end result is that even though gas deliveries will naturally 
taper off from the Permian and San Juan Basins, there could be a 10 percent 
pipeline capacity shortage in the Southwest by the mid 1980' s if Western 
Alaskan gas is sent by the displacement. 

The direct delivery of Alaskan gas via a western leg involves expanding 
the carrying capacity through looping the existing Pacific Gas Transmission 
and Pacific Gas and Electric Company pipeline system. This system currently 
transports 1.4 bcfd of Canadian reserves to Washington, Oregon and Idaho 
as well as California. The existing system could not be utilized for 
Alaskan gas deliveries without looping because it is now operating at 
full capacity and will continue to do so until at least 1985. There are 
currently four principal contracts in which Canadian is delivered via 
the PGT and PG & E systems directly to California. Their volumes and expected 
expiration dates are as follows: 



The table shows that the existing pipeline should be operating at 
capacity until 1985 and could only handle most of the Alaskan gas after 
1986 or three years after the Alcan project is supposed to be completed. 



Authorized Average Daily 
Volume (in bcfd) 



Expiration 
Date 



.18 
.42 
.21 
.21 



10-31-85 
10-31-86 
10-31-89 
10-31-93 



296 

In sum, the displacement plan to deliver the western share of Alaskan 
natural gas has a lower front end cost than the direct delivery alternative, 
but it consumes more energy delivering the gas and could cause a pipeline 
capacity shortage in the future. While the existing direct delivery system 
is operating at capacity, pipeline facilities could be expanded economically 
by looping or paralleling the present pipeline. 

The President's Decisions and Report to the Congress outlines a plan to 
construct a western leg which will expand the direct delivery system to 
carry an additional .70 bcfd of Alaskan gas. PGT intends to deliver .02 bcfd 
of it to the Northwest Pipeline Company for distribution in the Pacific 
Northwest, with the remainder going to California, where .20 bcfd would 
be distributed by PG & E in Northern California, and .44 bcfd would be 
distributed by the Southern California Gas Company in the southern part 
of the State. However, to emphasize the complexity of the western leg 
issue, the report advises the Secretary of Energy to do another study 
on the factors affecting the western leg distribution system before DOE 
issues the final certificate of public convenience and necessity, probably 
in 1980. The study could result in final changes in the capacity of the 
direct delivery system and in some utilization of the displacement option 
as something more than just a back-up system. 

3.2.6.7. Financing . The Alcan project contains two factors that will 
make it the most challenging and perhaps the most difficult ever to finance. 
One factor is the project's organizational complexity. Each of the four 
proposed segments of the project — the Alaskan section, the Canadian 
section, and the eastern and western extensions into the lower 48 States 
— will be operated and financed largely by different companies. In addition. 



297 

there is the regulatory complexity of dealing with the U.S. and Canadian 
Governments. Already the current delay in the Canadian Government passing 
Federal legislation authorizing the pipeline and a lack of U.S. Federal 
commitment on Alaskan natural gas pricing and end-user pricing threatens 
to delay construction of the pipeline. Each year's delay is estimated 
to add $1 billion to the project's financing requirements, due to inflation. 

The other factor is the project's total cost, which is estimated at 
$10 billion and could increase 40 percent or more before the project is 
finally finished. Financing $10 billion under the best of circumstances 
would be difficult, but what makes it even more difficult in this case is 
that the project cost is such a large percentage of the total worth of Alcan's 
pipeline companies ($26 billion in 1975). 

The traditional way of financing a project was to have the sponsor- 
ing pipeline(s) finance the entire project through "balance sheet" financing. 
The Alcan project, however, contains a new financing approach called "project" 
financing. A new project entity will be created and will be expected to 
generate sufficient revenues on its own in order to pay its operating 
costs, meet its debt obligations to lenders and turn a profit for its 
shareholders . 

The two factors of complexity and total cost pose large scale risks 
to financial backers of the project. The normal project risks of non-completion 
abandonment after completion, interruption of service and cost overruns are 
higher than usual, and if the project entity runs into financial trouble, 
lenders could face a financial crisis. As a result, the lenders will look 
to minimize their risks as much as possible through institutional arrangements 



298 

such as financial guarantees before they (lenders) will commit billions 
of dollars to the Alcan project. 

The President's Decision and Report on the Alaska Natural Gas Transporta- 
tion System recommends a project financial plan which encourages financing 
totally in the private sector (see exhibit 1). The plan shows both the 
Alcan and Canadian sections will probably be financed on a 3-to-l or 4-to-l 
debt-to-equity basis. Debt is money loaned over a specific period and 
requires periodic interest plus principle payments. Equity is money that 
is invested in the company through issuance of stock which entitles the 
investor to voice some opinion on company policy. If the company or project 
fails and the assets are liquidated, lenders of debt are compensated first, 
then the equity investors. Consequently, there is more risk to the loss 
of equity money than debt money. 

Alcan 's transmission company partners (sponsors) will initially contribute 
$935 million in equity into a separate company called the Northwest Alaska Pipe- 
line Company. A consortium of banks, led by Bank of America, is expected to 
provide an additional $925 million in front-end loans (debt) for the initial 
construction phase of the project. The Canadian Foothills group has planned 
its financing along similar lines with $855 million in equity from the pipe- 
line partners and $542 million in bank loans. 

The project's long term financing of debt will be mainly in the form of 
20-year bonds. Alcan, Foothills and the Northern Border Pipeline consortiums 
have indicated that they will issue their own bonds separately, but will 
market them together to financial institutions. The West Coast extension 
however, will be financed entirely and separately by the Pacific Gas Trans- 
mission Company and Pacific Gas & Electric Company. 



299 



Exhibit 1 



Adjusted Financing Requirements 
of Conpanies Associated with 
THE ALCAN PIPELINE PROJECT* 
(1979-1983) 
(Dollars in Millions) 



ALCAN PIPELINE 

U.S. Banks 

U.S. Long Term Debt 

U.S. Common Stock 



FOOTHILLS GROUP 

Canadian Banks 
U.S. Long Term Debt 
Canadian Long Term Debt 
Canadian Common Stock 



PG&E 



U.S. Banks 

U.S. Long Term Debt 

U.S. Common Stock 



PG&E 

U.S. 
U.S. 
U.S. 



Banks 

Long Term Debt 
Common Stock 



NORTHERN BORDER 

U.S. Banks 

U.S. Long Term Debt 

U.S. Common Stock 



TOTAL 

Canadian Funds 
U.S. Funds 



$314 



1,649 
$2,055 



3,416 
$4,113 



3,396 
$3,661 



1979 


1980 


1981 


1982 


1983 


Total Basic 












Requirements 


$ - 


$ 38 


$ 590 


$ 29 7 




$ 925 




744 


638 


478 


- 


1,860 




372 


287 


276 




935 




$1,154 


SI . 515 


$1,051 




$3,720 




117 


319 


106 




542 ' 




341 


1,103 


782 




2,227 


80 


106 


106 




153 


4 4 5 


234 


183 


272 


158 


7 


855 


314 


747 


■ 1,800 


1 046 


1 fin 


*t , U O 7 


- 


- 


- 


412 


- 


412 








412 




4T? 




87 


218 


82 




387 




87 


218 


81 




387 








308 




308 




49 


436 


494 




979 




17 


145 


266 




427 




68 


581 


1,068 




1,714 


314 


406 


697 


265 


160 


1,842 



$160 



8,460 
$10,302 



* Based upon financial plan presented to White House Staff on August 2, 1977, adjusted 
to reflect one and one-quarter year lag in outlays and 5 percent inflation factor. 



300 

The President's Decision and Report also outlines a series of condi- 
tions under which private sector financing is expected to occur. The 
plan states the equity investment in the project would be placed at 
risk under all circumstances and the budgeted equity investment be considered 
the first funds spent. A higher rate of return than normal on equity 
would compensate pipeline sponsors for bearing this risk providing the 
project does not produce large cost overruns. The variable rate-of-return 
would vary depending on how close construction costs came to original 
estimates. The greater the cost overruns, particularly if above 35 percent, 
the lower the rate of return on equity. If the project cost near the 
original estimates, the rate-of-return on equity would be approximately 
15 percent rather than normal 12.5 to 14.0 percent. 

Two guarantees for the project are recommended after its completion. 
First, the variable rate-of-return scheme includes a provision requiring 
"reasonable cost overruns" be part of the tariff charged to gas consumers. 
If the project is over its budget, the higher total invested capital reflected 
in a higher tariff would be partially offsej: by a lower allowed rate of 
return on that capital but the gas consumer will still assume some of 
the cost overrun. The second guarantee is that in the event of service 
interruption by the pipeline, the gas consumer would assume the payment 
of the project debt through his pipeline tariff, the debt principle 
and interest obligation. The two guarantees serve to lower the risk 
to the project after its construction and they serve to avoid any consumer 
guarantees in the event the project is not completed. The variable rate- 
of-return, in comparison, is designed to maintain risk during the construction 
phase and provide some incentive encouraging efficient management of the 
project . 



301 

The President's Decision and Report recommends that the Alaskan natural 
gas producers and the State of Alaska, as major beneficiaries of the project 
participate in the financing either directly or in the form of debt guarantees 
While the Alaskan gas producers, Exxon, Atlantic Richfield, and the Standard 
Oil Company of Ohio, are prohibited, for antitrust reasons, from buying 
equity in the project, they could buy project debt, or provide some guarantee 
for the debt. With 1976 total assets of $51.6 billion and a net income 
of $3.4 billion, the producers' participation would significantly bolster 
the credit rating of the project. 

The producers have indicated, however, a lack of interest in such 
participation because of their probable involvement in the $2.6 billion 
gathering pipeline system servicing the main Alcan pipeline. 

The State of Alaska would benefit substantially from the Alcan project. 
The Administration predicts that Alaska could realize as much as $7.5 
billion (1977 dollars) from the sale of Prudhoe Bay natural gas in the form 
of royalties and severance taxes. The State would also realize about 
$50 million per year in property taxes. Other benefits include the State 
utilizing the pipeline for its own gas development program which would 
contribute significantly to any long-term economic development program 
in the State. Some months ago, Alaska was willing to guarantee up to 
$900 million of the losing El Paso project debt, but has remained uncommitted 
on the Alcan project. 

While project guarantees and a favorable rate-or-return are important 
in any financing plan , it is only half the picture in determining the 
ultimate f inancibility of the Alcan project. The other half of the picture 



302 

concerns the Federal pricing policy on Alaskan gas. Specifically, two 
critical Federal decisions, on the wellhead price of the gas, and the end-user 
pricing structure of the gas, must be made before potential financial 
backers of the project can make a decision on the Alcan project. 

3.2.6.8. Wellhead Pricing and End-user Pricing. There are two main 
end-user pricing alternatives. The first is the "rolled-in" pricing structure 
where the price of Alaskan natural gas would be averaged in with the prices 
of the cheaper existing gas supplies producing a higher gas price for 
all consumers in the system, but a lower price than the actual cost of the 
Alaskan gas. The other is an "incremental" pricing structure, where the 
actual end-user of Alaskan gas would pay the full delivered price of that 
gas, while the user of non-Alaskan gas would continue to pay the lower price 
of delivered existing gas. Those end-users using some of each would be 
charged a weighted price based on the percentage of Alaskan gas used and 
existing gas used. 

The President's positions on wellhead pricing and end-use pricing of 
natural gas are contained in the Administration's National Energy Act 
(NEA) proposal. The NEA mandates an incremental pricing approach by 
allocating the cost of more expensive supplies of natural gas, to lower- 
priority users, rather than to the residential and commercial users having 
less ability to convert to other fuels. The plan also provides that gas 
classified as "old gas under a new contract" would be subject to a $1.45 
per thousand cubic feet (mcf) ceiling price. The President's Decision 
and Report states that Alaskan gas would be classified as "old gas under 
a new contract" and that the sale of Alaskan gas would be subject to the 



303 

incremental approach. However, it should be emphasized that there is no 
legislative language in NEA or in the House and Senate versions of NEA 
specifically defining this position. 

The Congress endorsed the President's incremental pricing position in 
both the House and Senate gas pricing legislation. Both bills provide that old 
gas cost would be allocated for rate purposes to high priority users, 
residential and commercial customers with less than 50 mc f of gas consump- 
tion on a peak (the Senate bill includes hospitals and essential agricultural 
consumptions). In the House version, when gas prices to low priority users 
exceed substitute fuel levels, further cost increases would be shared by 
both high and low priority consumers. This protects high priority consumers 
from old gas wellhead cost increases resulting from changes in the mix of old 
gas vintages. Under the Senate provision, high priority users would pay 
for wellhead cost increases due to the changing mix of oil gas vintages. 
The main difference between the two bills is the House version requires 
the local distribution company to pass through the incremental charges to 
their low priority customers while the Senate version does not. If incre- 
mental pricing is not required of the distribution companies, the resulting 
pricing system will be a modified rolled-in pricing system since most of the 
State utility commissions still practice rolled-in pricing. 

Without definitive Congressional decisions on Alaska gas wellhead 
pricing and end-use pricing, the Department of Energy (DOE)'s Federal 
Energy Regulatory Commission (FERC), which absorbed the old Federal 
Power Commission, will be charged with making the decisions. 



304 

To establish a wellhead price for Alaska gas, FERC will have to initiate 
a price proceeding and hold extensive hearings on cost allocations which could 
take a long time to establish. One factor that will complicate the wellhead 
pricing decision for FERC is that Alaskan gas will be produced in association 
with Alaskan oil. When associated gas is produced, it is difficult, if 
not impossible to determine the costs of finding, developing, and producing 
only the gas. As a result, the traditional cost-based pricing method 
of determining the price of the associated gas becomes somewhat arbitrary. 
In recent years, the FPC has priced all gas in a particular area based 
entirely on the cost of producing only nonassociated gas. FERC does not 
have the benefit of having data about nonassociated gas in Prudhoe Bay, 
because there is none, 

To expedite the FERC pricing procedure, the Administration has 
proposed to switch from cost-based pricing of Alaskan gas to commodity-value 
pricing: pegging the worth of the Alaskan gas to its reasonable value 
based on market conditions. The Administration presumably assessed the 
market conditions to conclude the gas should be priced at $1.45 per mcf. 

FERC will also decide whether Alcan is to charge gas distributors 
an incremental price or a rolled-in price for delivered Alaskan gas. 
Traditionally, the FPC has had a rolled-in pricing policy for interstate 
pipelines. But what makes Alaskan gas warrant different consideration is 
its high delivered costs — it is estimated that Alaska gas could cost as 
much as $5.35 per mcf, most of which ($3.00 per mcf) would be transportation 
costs. Some experts have warned that the high transportation costs necessitate 
a "rolled-in" pricing policy; otherwise the price of Alaska gas could 
be so high as to jeopardize the marketability of the gas, and as a result. 



305 

the f inancibility of the project. Rolled-in pricing would assure marketability 
because the resulting average price for gas would be far less than the 
delivered Alaskan gas price. 

Proponents of incrementally pricing Alaskan gas, however, believe 
the higher priced gas rolled-in with the cheaper existing gas would give 
consumers the wrong "impression " on the costliness of future gas supplies. 
They argue that the use of incremental pricing promotes efficient use 
of gas and subjects the user to the market test of paying the true cost of 
supplying the expensive gas. 

Others respond by pointing out that the Federal Government has in 
the past rolled-in higher-cost fuel types in other regulated energy sector 
so why not do the same for natural gas. Electricity generated by oil-fired 
generating stations costs substantially more than the average cost of 
electricity, but it is sold to consumers on a rolled-in basis. In addition, 
the cost of high-priced imported crude oil is rolled-in with the cheaper 
U.S. domestic oil to determine its price price to consumers. 

The debate over rolled-in and incremental pricing has raged for some 
time in establishing a liquefied natural gas pricing policy. The current 
method of forming LNG pricing policy between pipeline and distributor is 
for doe's Economic Regulatory Authority (ERA) to decide the pricing issue 
on a project-by-project basis. In the first two LNG projects, the El Paso I 
and Truckline Gas Company, the FPC, ERA's predecessor, ruled in favor of 
a rolled-in pricing scheme. ERA's latest decisions, involving the Pacific 
Indonesia and Distrigas LNG projects, contain incremental pricing schemes, 

24-786 O - 78 - 21 



306 

but only at the wholesale level, the level of sale between the pipeline 
and distributor. An LNG incremental pricing scheme strictly at the whole- 
sale level results in a modified rolled-in pricing system because, as pre- 
viously stated, States for the most part, practice a rolled-in pricing 
scheme for the distributor selling to the end-use customer. 

One predominate theme in the LNG project proceedings is that a rolled-in 
pricing scheme would be the most advantageous pricing scheme to insure 
adequate financing of an involving high priced natural gas. This position 
is reiterated by a Treasury Department study on the Alaska gas transportation 
issue. The study points out that rolled-in pricing for Alaskan gas would 
go the farthest to facilitate financing the transportation system, but 
added that the approach recommended in the Administration's National Energy 
Plan (Act) could go equally far if the Administration properly structures 
its pricing mechanism. It concludes by stating that a fully incremental 
pricing system would make the project's financing more difficult. 

The most favorable wellhead price for project financing depends on 
the end-use pricing structure. If the Congress or FERC rules in favor of 
a strict incremental system, between pipeline and distributor and between 
distributor and end-user, then too high a wellhead price would create 
high marketability risks; too low a wellhead price could discourage the gas 
producers from contracting with the pipeline to sell the gas. Without 
signing a sales contract, the producers could delay the project for quite 
a while even though the producers could do little less with the produced 
associate gas except reinject it back into the ground. If a full or 
modified rolled-in system gets the nod, marketability would be of little 
concern, but FERC would have to insure a reasonable wellhead price encouraging 
producers to sell the gas, at a reasonable profit. 



307 

In sum, the Federal Government has a great deal of control over how 
the Alcan project will operate financially after its construction. The 
Government controls the wellhead price of the gas, and to a large degree 
the selling price to end-use consumer, as well as the rate of return on 
investment in the pipeline. The Government also controls to a significant 
certain degree the project's potential cost overruns because until the 
Government makes its final decisions on the project, crucial private 
sector decisions will have to wait. First, Alcan cannot contract with 
the gas producers without a natural gas wellhead price. And, second, Alcan 
cannot go to lenders and ask for financial backing until there is a good 
idea about the marketability of the gas and the pipeline's rate-o f-return 
on investment. It is estimated that inflation will add about $3 million 
to the project's cost for every day of its delay. 

3.2.6.9. Guarantees . While the impact of the Federal Government's 
crucial decisions on the project remain undefined, potential financial 
backers of the project are saying they need more guarantees insuring the 
pipeline's completion. The Administration is pressing the State of Alaska 
and the gas producers to provide some guarantees to help complete the 
project. The Administration has decided the end-use consumer should not 
provide any guarantees during the construction phase of the project, but 
could provide some guarantees after the pipeline's completion. 

The Administration was also explicit that the Federal Government would not 
provide guarantees or any other financing assistance to the project before, 
during or after the project's completion. The following reasons were given: 



308 

1. Serious questions of equity result from the transfer of risks 

to taxpayers, many of whom are not gas consumers or will not receive ad- 
ditional gas supplies as a result of the Alaskan project. 

2. Federal financial support substitutes the Government for private 
lenders in the critical risk assessment function normally performed by pri- 
vate lenders. 

3. A subsidy in the form of lower interest rates yields an artificially 
low price for gas. 

4. The incentive for efficient management of the project is reduced. 

5. The Government is placed in conflicting roles as guarantor and as 
regulator of the project. 

6. Providing unnecessary Federal assistance to this project would set 
a precedent with respect to other large energy projects that is misleading 
and counterproductive. 

If however, events transpire in such a way as to warrant Federal in- 
volvement in some aspect of financing the Alcan project, Congress has 
several financial assistance options available to it. Three of the major 
options are the following: (1) to guarantee a specified amount of the cost 
overrun financing, (2) to guarantee of all or part of the project debt, and 
(3) to make a direct Federal loan. 

Under the cost overrun option, conventional lending sources would put 
up a specified amount of financing for the project based on the project's 
economics and the credit strength of the project's direct beneficiaries. 
A cost overrun estimate of 20 percent for example would be included in the 
project's original financing proposal. The Federal Government would guarantee 
a specified amount of additional cost overrun that is beyond the 20 percent. 



309 

The advantages of this option are (1) that it limits the tax payer's liability 
to a specified amount and (2) that it requires Government involvement only 
if the cost overrun exceeds a certain predetermined amount. The disadvantages 
are (1) that it reduces incentive to -ninimize the cost overrun and (2) that 
the cost to the Federal Government is likely to materialize, since the 
probability of some cost overrun is great. 

The Federal Government in the second option would guarantee all or part 
of the debt issue by Mean. The advantage is that it minimizes financial 
risk, insuring that lenders will advance funds to the project. The disadvantag 
are (1) that it means substantial and lengthy involvements for the taxpayer, 
(2) that it reduces incentives to minimize cost overruns and (3) that 
it means all taxpayers would bear some of the project's risk in lieu of 
the project's direct beneficiaries. 

The third option would have the Federal Government directly funding 
of the project. The advantages are (1) it insures the availability of 
financing for the project and (2) it means some savings in financing costs 
because the rate for long-term Government funding would be lower than 
the interest rate Mean would pay for its guaranteed or nonguaranteed 
financing. The disadvantages are first, it could mean a prolonged funding 
program potentially lasting the 20-year life of the project and second, 
the cost to the taxpayer could be billions if the project has a large 
cost overrun. 

3.2.6.10. Conclusion . Any serious discussion of Federal options for 
financing the Alcan project will have to wait until crucial decisions are 
made which further define the project's financial structure. The decisions 
include the U.S. Government ruling on the wellhead price of natural gas, the 
end-use pricing structure associated with higher priced gas, and the rate of 



310 

of return on investment associated with the Mean pipeline. The timing of 
these decisions will influence to. a significant degree the project's potential 
cost overruns because crucial private sector decisions will have to wait for 
government's decisions. For example, Alcan cannot contract with the gas pro- 
ducers without a natural gas wellhead price. And Alcan cannot go to lenders 
and ask for financial backing until there is a good idea about the marketabil- 
ity of the gas and the pipeline's rate-o f-return on investment. Any delays in 
schedule are estimated to add about $3 million to the project's cost for 
every day of its delay. 

While the impact of the Federal Government's decisions on the project 
remain undefined, potential financial backers of the project are saying 
they need more guarantees insuring the pipeline's completion. The Admin- 
istration has ruled the end-use consumer should not provide any guarantees 
during the construction phase of the project, but could provide some guaran- 
tees after the pipeline's completion. The Administration was also explicit 
that the Federal Government would not provide guarantees or any other financing 
assistance to the project before, during or after its completion. The State 
of Alaska and the Alaska gas producers as two of the main beneficiaries of the 
project were encouraged to provide some guarantees for completing the project. 

In sum, the need for Federal financial involvement in the Alcan project will 
primarily depend on how and when the U.S. Government makes its project decisions 
coupled with whether or not Alaska and the Alaskan gas producers decide 
to offer project guarantees. 

The role of Congress during this period could be to oversee the decision 
process by evaluating the impact of each important decision on the project. 
Testimony from each major project participant would be most useful in making 
a complete evaluation of the decisions. Periodic evaluations on the project 



311 



decisions would keep the Congress up-to-date on the pipeline's progress 
as well as keep the Congress informed on the necessity for Federal 
assistance with project financing. 



References 

U.S. Congress. House. Committee on Interior and Insular Affairs. Sub- 
committee on Public Lands. Hearings, 95th Congress, 1st session, 
Transportation of Alaska Natural Gas. February 17, 1977. Washington, 
U.S. Govt. Print. Off., 1977. 225 p. 
"Serial No. 95-4." 

. Hearings, 94th Congress, 1st session, Alaska natural 

gas transportation system, Oct. 9, 1975. Washington, U.S. Govt. Print. 
Off., 1975. 340 p. "Serial no. 94-36" 

U.S. Congress. House. Committee on Interstate and Foreign Commerce. 

Subcommittee on Energy and Power. Transportation of Alaskan natural 
gas. Hearings, 94th Congress. 2nd session. May 17, 18, and 19, and 
August 6, 1976. Washington, U.S. Govt. Print. Off. 1976. 714 p. 
"Serial no. 94-133." 

U.S. Congress. Senate. Committee on Energy and Natural Resources. Hearings 
95th Congress, 1st session. Alaska natural gas transportation system. 
September 26, 26, October 11, 12 and 25, 1977. Washington, U.S. 
Govt. Print. Off. 1977. 868 p. Publ. no. 95-73. 

U.S. Congress. Senate. Committee on Interior and Insular Affairs, 

and Committee on Commerce. Hearings, 94th Congress, 2nd session. 
The transportation of Alaskan natural gas. Parts 1, 2, and 3. Feb. 17, 
Mar. 24 and 25, 1976. Washington, U.S. Govt. Print. Off., 1976. 2030 p. 
"Serial no. 94-29" and "Serial no. 94-72." 

Reports 

Canada National Energy Board. Reasons for decision on northern pipelines. 
Ottawa, July 1977. 3 volumes. 

Executive Office of the President. Energy policy and planning. Decision and 
report to Congress on the Alaska natural gas transportation system. 
Washington, September 1977, 271 p. 

U.S. Dept. of Justice. Alaska natural gas transportation systems: report 
on antitrust issues. Washington, July 1977, 82 p. 

U.S. Dept. of State. Alaska natural gas transportation systems: Report 
on the international relations issue. Washington, July 1977. 



312 



U.S. Dept. of Transportation. Alaska natural gas transportation systems: 
safety and design. Washington, July 1977. 44 p. 

U.S. Dept. of the Treasury. Financing an Alaska natural gas transportation 
system. Washington, July 1977. 

U.S. Federal Energy Administration. National economic impact of Alaska 
natural gas transportation systems. Washington, July 1977. 54 p. 

. Supply, demand and energy policy impacts of Alaskan gas. 

Washington, July 1977. 183 p. 

U.S. Federal Power Commission. Recommendation to the President. Alaska 

natural gas transportation systems. Washington, U.S. Govt. Print. Off., 
May 1977. 



White House Task Force. Alaska natural gas transportation system: report 
on construction and cost overruns. Washington, July 1977, 131 p. 



313 

3.3. ISSUES AND PROBLEMS RELATED TO IMPORTED ENERGY 



I 



315 

3.3.1. Deepwater Port Siting and Licensing * / 

The transportation of oil by large tankers has become a reality 
since the technology is available and the economics clearly favor their 
use. The ports of the United States along the East and Gulf Coasts are 
not capable at the present time of accommodating these large vessels, and 
it is not believed to be feasible to enlarge and deepen them in order to 
do so. Instead it has been proposed that the large tankers unload their 
cargo at deepwater ports offshore. Congress has enacted legislation, the 
Deepwater Port Act of 1974, that would permit the construction and opera- 
tion of ports offshore where the depth of the water would allow the loading 
of petroleum from tankers. Most of the impetus for this legislation came 
before the 1973-74 Arab oil embargo, which dramatically pointed out this 
country's vulnerability to foreign imports of this energy resource. 
Although legislation exists that would permit the construction of deep- 
water ports, and two are presently in the planning stages for the Gulf of 
Mexico, the issue is: Should the United States reassess from a national 
interest and security standpoint the desirability of permitting deepwater 
ports off our coast that may, in view of their cost both in construction 
and operation, lock this country into an energy policy of continuing to 
increase the importation of oil? 

3.3.1.1. Background . The transportation of oil has progressed 
from bottles to huge tankers. The historical evolution of the oil 
transportation industry is set out in Volume I of this study on pages 159-197. 

*/ Prepared by Thomas E. Kane, Analyst, Environment and Natural Resources 

Policy Division. 



316 

What it makes clear is that changes in transportation patterns 
have taken place for economic reasons as rapidly as technology 
has permitted. 

Over the last three decades tanker technology has evolved rapidly. 
For instance, at the end of World War II, tankers averaged 20,000 dead- 
weight tons (DWT), and by 1955 the largest tanker in the world was 47,000 
DWT. In less than 20 years, a 477,000 DWT tanker was launched, in 1973, 
and presently the tankers have grown to over 500,000 DWT with drafts in 
excess of 90 feet and lengths of 1,200 feet. The tankers break down ac- 
cording to size into the following categories: Tankers (20,000-50,000 
DWT with 40-feet drafts); Supertankers (up to 200,000 DWT with drafts 
plus or minus 60 feet); Very Large Crude Carrier (VLCC) (200,000-500,000 
DWT with drafts between 70 and 100 feet); and Ultra Large Crude Carrier 
(ULCC) (500,000 - 1 million DWT with drafts exceeding 100 feet). 

The dramatic increase in the size of petroleum tankers, as is the 
case with other advances in the transportation industry, is a result of 
the desire to increase the efficiency and decrease the costs of shipping. 
Shipping costs for the United States have continued to rise since this 
Nation has had to increase its imports from the Middle East and North 
Africa. The main causes were the Arab oil embargo of 1973-1974, and the 
resulting quadrupling of oil prices as well as the greater distance the 
oil must travel to reach the U.S. Traditionally the United States, when 
it needed to import oil, did so from the Caribbean and South American 
countries, as well as Canada. As our need for imports increased and these 



317 

regions were unable to meet our demands, the United States has become 
more dependent on the Middle East and Africa for its supplies. 

The United States has increased its dependency on foreign sources 
for crude oil from 18 percent in 1960, to 29 percent in 1972, and 40 per- 
cent in 1975. Estimates place the percentage of imports by 1980 at 50 
percent, and most of these will come from* the Middle East. Since the 
oil must be shipped more than 12,000 miles to the United States from 
this region, it is easy to understand the desirability of using larger 
tankers with their lower unit costs. However, the ports along the East 
and Gulf Coasts of the United States are not capable of handling tankers 
over 45 feet in draft, so other means have had to be devised to utilize 
the larger tankers. At the present time this is accomplished by trans- 
shipment from ports in the Caribbean where the VLCCs off-load their 
cargo into smaller vessels that may then enter U.S. ports. A proposed 
alternative method of off-loading oil for the United States involves 
the use of deepwater ports far enough off our coasts to accommodate 
the deep-draft vessels. 

Legislation was introduced in the 93d Congress to address the matter 
of deepwater ports. Nineteen bills were introduced in the House and the 
Senate which would have provided by various methods the statutory frame- 
work to permit the construction and operation of these ports off the 
shores of the United States. The principal bill in the House was 
H.R. 10701, and S. 4076 emerged as the principal Senate bill. The major 
concerns raised during the legislative process included: (1) the role of 



318 

the States (which ultimately included a veto power); (2) the environmental 
dangers, specifically relating to oil spills, construction activity and 
maintenance of the port (which led to inclusion of specific environmental 
criteria and procedures, including an environmental impact statement, and 
the establishment of an oil spill liability fund); (3) the desirability 
of expanding or deepening existing channels and harbors (which must be 
considered before a deepwater port is authorized); (4) the possibility of 
relying on other forms of energy (which is not considered practicable in 
the foreseeable future to meet the nation's energy needs); and (5) the 
anti-competitive nature of the ports if constructed and operated by the 
oil companies (which is addressed in the law by requiring the review of 
the application by the Attorney General and the Federal Power Commission 
for possible antitrust problems) . 

The House and Senate, which passed different versions of the bill, 
agreed on compromise legislation and the measure was passed on 
December 17, 1974, and signed into law by the President on January 3, 1975 
(Pub. L. 93-627, 88 Stat. 2126). The Deepwater Port Act was amended in 
1977 with the enactment of Pub. L. 95-36, but this amendment merely 
extended the authorization for appropriations for the administration of 
the Act for three additional years through September 30, 1980. 

3.3.1.2. Analysis . An important energy policy question centers 
on the relationship between the construction of deepwater ports, 
which would undoubtedly increase the efficient importation of 
oil, and the growing dependence of the United States on foreign 
imports. It is anticipated that imports will rise from the present 



319 

7.2 million b/d (1976) to 10 million b/d (1980), 11.8 million 

1/ 

b/d (1985), and 12.9 million b/d (1990) in the next 14 years. 
What is of even greater concern is that these imports will primarily 
come from the Middle East and North Africa (projected to be 60 
percent of imports in the early 1980s), where there is less govern- 
mental stability, rather than from areas in the Western Hemisphere where 
the United States has traditionally obtained the imports it has needed. 

The construction of deepwater ports thus raises serious questions 
about the U.S. energy policy of importing crude oil from the Middle East 
and North Africa, and the vulnerable position in which it places this 
nation's energy supply. Deepwater ports may very likely encourage the 
increase in imports to justify the costs of construction and maintenance. 
At the very least, it is clear that the relative economics of transport 
from different sources will change, so the mix of sources will also 
change if FOB prices are not adjusted to reflect transport economics. 
It would appear that a review of the desire to have deepwater ports 
would be an important step in assessing this country's energy policy 
relating to imports. This should be accomplished before the ports 
are built since once the ports exist the issue may be moot. 

1^/ U.S. Congress. Senate. Committee on Energy and Natural Resource, 
Committee on Commerce, Science and Transporation , and the National 
Ocean Policy Study. House. Committee on Interstate and Foreign 
Commerce, Subcommittee on Energy and Power. Project Interdependence: 
U.S. and World Energy Outlook Through 1990. (Committee Print) 
Washington, U.S. Govt. Print. Office, 1977 (Pub. No 95-31) 99 p. 



320 

It is indisputable that the continuation of imports at this time is 
inevitable, that this Nation's imports of oil will increase in the fore- 
seeable future, and that using larger tankers will result in cheaper 
transportation costs and, thereby, make the imports more economical by 
somewhere between 30 cents to 50 cents per barrel. However, it may be 
that the Nation may trade long-term detriments for such short-term gains, 
if the overall source of imports is shifted by cheaper transportation to 
less secure sources. 

Not only will the ports encourage imports but they may discourage the 
development of other forms of energy, as well as conservation efforts. A 
considerable expense is involved in building and operating deepwater ports. 
The capital costs alone are estimated to be in excess of $800 million for 
each of the two ports which have been considered for the Gulf of Mexico. 
The time needed to recoup the investment may influence the Nation's energy 
policy for many years. The economic and political pressures may continue 
to encourage the importation of oil through deepwater ports when the 
national interest favors a lessening of our dependence on foreign oil. 
Although it is safe to say that nearly everyone in this country favors 
lessening the amount of oil imports, they are not likely to decrease — 
much less cease — in the foreseeable future. There is no doubt that if 
the national interest was cl ear ly opposed to the increase in imports, they 
would cease. Yet the national interest or security are elusive concepts 
and may be pulled in the direction of continued use of expensive deep- 
water ports through economic and political pressures, although national 



321 

energy policy may best be served by a different approach. Economic pres- 
sure would not be limited to the large capital investment involved nor 
the lower transportation costs expected; but, would include the costs of 
removing the facilities once the operations of the deepwater ports ter- 
minate. One estimate put these removal costs in excess of $6.6 million. 

Possibly the most serious transportation question involved if deep- 
water ports were not permitted would be the cost of importing oil and 
whether other alternatives are available for a short-term answer to the 
unquestioning need in this country for more imported oil. If viable 
alternatives do exist which may even include higher costs, the national 
energy policy could be shaped in that direction in the interim while 
long-term solutions are sought . 

Since the Deepwater Port Act became law in 1975, there have been 
two serious proposals — LOOP, INC. offshore Louisiana and SEADOCK, Inc. 
off the coast of Texas — for the establishment of deepwater terminals. 
It now appears, however, that only LOOP is likely to be realized in the 
foreseeable future since some financially important investors in SEADOCK 
have withdrawn from the venture. The timing for Congress to consider the 
issues raised here is critical since very likely the issues will be moot 
once the port or ports are constructed — or at least more difficult to 
reverse. Once construction has taken place the pressure will undoubtedly 
shift to the maximum efficient use of the ports to obtain the maximum 
benefits. Thereby, the usage of oil will continue to rise and delivery 
of imports of oil from foreign sources will continue to grow as well. 
Thus time is of the essence. 

24-786 O - 78 - 22 



322 

The impacts caused by deepwater ports upon the transportation and 
use patterns for crude oil may depend a good deal upon the resolution of 
the question of whether these ports will divert oil from the smaller 
ports that presently receive imported oil. Since imports are likely to 
increase in the future, it is not known if the smaller ports on the East 
and Gulf Coasts will receive less imports and suffer economic loss due 
to the existence of deepwater ports in the Gulf. However, in reviewing 
the anticipated capacity and throughput volume planned for one or both 
Gulf ports, it is possible that imports — and thus jobs — will be lost 
to the smaller ports. For instance, for the first five months of 1977, 
the crude oil imports by tanker or barge entering East Coast ports averaged 
1.4 million b/d, and 2.44 million b/d for the Gulf ports. The average 
throughput capacity for LOOP when fully operational (1989) is 3.4 million 
b/d, with the possibility, with increased pumping horsepower, of reaching 
5.7 million b/d, with only a 60 percent berth utilization factor. If 
SEADOCK is constructed, the average throughput capacity when completed 
would be 4.0 million b/d, and could go as high as 4.8 million b/d with 
additional horsepower and a 60 percent berth utilization factor. 
Therefore, if both deepwater ports are constructed by 1990, they would 
together have the capacity of handling more than all of the U.S. crude 
oil imports anticipated for that period. Even if only one deepwater port 
(LOOP) were constructed, it would probably be able to handle all of the 
crude oil imports anyway since LOOP's final environmental impact state- 
ment (Vol. 4, p. C-43) points out that although "(t)he possibility of 



323 

only one deepwater port operating on the Gulf Coast is not considered a 
likely eventuality... (i)f only one deepwater port were constructed, it 
would be necessary to expand its throughput well beyond present proposed 
levels." Thus, the deepwater ports are being designed to have the 
capacity to handle substantially all of the crude oil imported into the 
United States. Whether this fact will result in crude oil imports being 
diverted from smaller ports and refineries to the deepwater ports and the 
planned new refineries associated with them is not certain. Nevertheless, 
the question warrants serious consideration in view of the possible social 
and economic impacts which may result at existing, smaller ports. If no 
significant impacts are encountered over that issue, and although the 
volume of oil will increase out of necesssity, it is not clear what, if 
any, impact on the transportation and use pattern of oil will result. 

A realistic assessment is needed of other energy sources. The 
assessment should consider the practicality and timeliness of other 
resource uses such as solar, wind, tidal, coal, OTEC , etc. Addition- 
ally, an analysis of the likely results of conservation measures that 
may effect energy demand is required before a rational decision can 
be reached on the issues. 

As mentioned, if a decision by Congress on reassessing the needs and 
desires of the Nation relating to deepwater ports is not made before one 
or more of the ports are constructed the very existence of them may en- 
courage and foreclose for the time being the lessening of our dependence 
on insecure sources of petroleum from the Middle East and North Africa. 



324 

3.3.2 Tanker Design and Safety Regulation * / 

Increased waterborne transportation of oil and liquified natural 
gas, and several accompanying accidents, have caused a mounting national 
concern for more stringent tanker design and safety regulation. The growth 
of both the tanker trades and the dead weight tonnage of the average tanker 
in the past decade has posed new problems in respect to maneuverability, 
potential for loss of life and property, and damage to natural resources. 
Previous sections of this report have focused on the interconnectednes s of 
the national energy transportation system, especially on its dependence 
on the tanker transported crude oil trade. Any design and safety regulation 
of the tanker-fleet might thus have significant effects on the entire 
national energy transportation system. The issue is what these effects might 
be. 

3.3.2.1. Background . Traditionally the United States, as a major 
maritime nation, has had a national policy of promoting maritime commerce 
and aiding navigation. Until fairly recent times the regulation of tanker 
design and setting of safety standards were not an integral part of 
the normal regulatory process. Increased tanker trade after World War II 
brought greater congestion to most U.S. ports. An incident occuring 
in San Francisco harbor in 1971 brought to the front the change that 
had taken place in the entire ship navigation spectrum. After the tragic 
accident and oil spill at that time, the National Traffic Safety Board 
called for increased regulation of vessel traffic and greater ship to 
ship communication, noting that it was no longer acceptable to allow 

^/ Prepared by Martin Lee, Analyst, Environment and Natural Resources 
Policy Division. 



325 

1/ 

the captain of each ship to make all the decisions regarding navigation. 

Immediately following this incident the Congress, in recognition of 

the growing importance of tanker regulation, passed the Ports and 

2/ 

Waterways Safety Act. The Act had the two-pronged focus of attempting 

to regulate navigation and hazardous cargos. 

Basic to an understanding of the tanker regulation issue, as well as many 

national energy transportation issues, is that of greatly increased oil imports 

via ocean-going tankers. Oil imports have risen steadily from 1.8 million 

barrels per day in 1960, to 7.3 million barrels per day in 1976 , a four-fold 

3/ 

increase in oil imports. The 1976 amount represented approximately 42% 
of the total oil consumed in the U.S. in 1976, a fact that gives great 
emphasis to the dependence of the national energy needs on tanker-transported 
oil. This emphasis is further highlighted by estimates for future oil imports, 
some of which are projecting imports of 12.9 million barrels per day by 1990 
— a 77% increase over current imports. The importance of the growth 
in oil imports and the projections for furture growth have had their effects 
on the tanker trades which have corresponding growth rates. 

Of this oil import trade, U.S. -owned private tankers have very little 

5/ 

part. A noted in Volume I, only 4.78% of imported oil is currently car- 
ried on U.S. flag tankers. The U.S. tanker fleet is old and outdated, with 

\l See S. Rept. 91-12h. p. 6. 

1/ 33 U.S.C. 1221-1227. P.L. 92-340. 

3^/ Federal Energy Administration. Energy in Focus, Basic Data. 1976. 

4/ House Committee on Interstate and Foreign Commerce, Energy Estimation 
Digest, p. 15. 

_5/ National Energy Trends and Choice, Vol. I, p. 238. 



326 

an average vessel age of 18 years and average deadweight tonnage of 27,000 DWT. 
There is a clear trend wordlwide toward larger tankers in the 200,000 DWT 
plus class to reduce the per mile cost of transporting oil. Of the seven crude 
tankers currently "on order" in the United States, all are over 200,000 DWT 
and three are 390,000 DWT each. The size of such tankers has already had great 
consequences on tanker design and safety regulations, since the newer tankers 
pose problems in respect to maneuverability and potential for explosion and 
acc ident . 

Corresponding to the growth in the tanker trade has been the rate of 
vessel accidents. This rise has been the basis for increased concern for 
tanker safety regulations. The Annual Statistics of Casualties , compiled 
by the Coast Guard, reveals a steadily increasing rate in the total number 
of casualties: 



6^/ Maritime Administration. Merchant Fleets of the World. Sept. 1976 p. 42,43. 
l_l Maritime Administration. U.S. Merchant Marine Data Sheet. April 1, 1977. 



327 



Casualties of Commercial Vessels S_/ 
1972-1976 



Fiscal Year Total CollisionsCall types) Explosions Groundings Others 



1972 2424 1085 

1973 3108 1258 

1974 3338 1213 
1973 3305 1335 
1976 4211 1539 



170 540 629 

147 650 1017 

183 797 1195 

206 786 978 

285 1130' 1257 



The recent (Dec. 1976) grounding and oil spill of the ARGO MERCHANT 

on the Nantucket Shoals demonstrated the costliness of a single 

spill. The value of the 7.5 million gallons of fuel oil lost was 

estimated at $2,362,500. GAO also estimated the entire cost of this 

incident, including the replacement cost of the oil, the ship, and 

9/ 

losses to government and private organizations, at $5,160,662. 
The ARGO MERCHANT , at 31,000 DWT , was a relatively small tanker, 
only a tenth of the size of the average crude tanker now being built. 

3.3.2.2. Analysis . While the trend toward more tanker accidents 
has been verified, it is necessary to look at what types of accidents 
make up these statistics in order to understand the tanker safety 
regulation issue more clearly. Collisions and groundings, as noted 

8/ U.S. Coast Guard. Statistics of Casualties. 1972, 1973, 1974, 1975, 
1976. 

9^/ General Accounting Office. Total Costs Resulting from Two Major 
Oil Spills. June 1, 1977. 



328 

account for approximately one half of these incidents, with structural 
failures, ramraings , and breakdowns being other important types of 
accidents . 

Current legislation does ai.Ti l aost of these types of accidents. The 

main Federal statute now covering s.^io navigation and vessel design is the 

10/ 

Ports and Waterways Safety Act of i972 (PWSA), which focuses on the 

various types of tanker accidents mentioned above. The Act, as mentioned, 

has two titles: Title I aims at vessel control and Title II at vessels 

carrying hazardous cargos especially oil. Through the establishment of 

vessel traffic systems (VTS) and collision avoidance systems (CAS) the 

Act seeks to utilize sophisticated computer /radar technology in regulating 

vessel traffic in a safe manner. Also vessel inspection and design criteria 

are prime components of this statute, A number of individual states 

have enacted their own tanker safety laws including Washington, Connecticut, 

and New Hampshire. Washington's Tanker Law, passed in 1975, is currently 

the object of a major case (Atlantic Richfield v. Ray, D.C. Washington. Sept. 

23, 1976) argued before the Supreme Court at the beginning of 

the October, 1977 term. Washington's law, which requires Washington 

pilots on tankers in Puget Sound, does not allow supertankers of more 

than 125,000 DWT) in Puget Sound and specifies certain design criteria 

on all vessels in Washington State waters has special significance 

in respect to the transportation of Trans Alaska Pipeline (TAPS) crude 

10/ 33 U.S.C. 1221-227. P.L. 92-340. 

11 / Note: After this writing, the U.S. Supreme Court in Ray v. Arco 

U.S. (1978) Docket No. 76-930, March 6, 1978, decided 

that U.S. law preempted in part Washington State's Tanker Law, 



329 

oil. Most of the fleet in this particular trade would be unable to 
enter Puget Sound under the Washington Tanker Law. The U.S. District 
Court in the Atlantic Richfield case struck down the Washington Law. 
If reversed by the Supreme Court, it could have significant effects 
on the tanker trade and possibly present an obstacle to consistent 
Federal regulation under the Ports and Waterways Safety Act. If states 
are allowed to have individual tanker safety statutes, a host of laws 
could be enacted, possibly overlapping or contradicting each other, 
restricting tanker trade more than a uniform law, and adding to transport 
costs. On the other hand, a Federal law adequate for most ports and 
coasts might prove inadequate in areas of extreme environmental sensitivity, 
such as Puget Sound. 

While it has been determined that there is a trend toward larger, 
more complex tankers, and that accidents are increasing and that there 
are Federal laws on the books which attempt to address the main problem 
areas, there nevertheless are a number of other factors which make 
tanker design and safety regulation an issue. 

With most of the U.S. flag fleet in an aging condition and with 
the great majority of our imported oil arriving on foreign controlled 
tankers, there is concern for the safety of life, property and natural 
resources. Following a Presidential initiative of March 1977, a number 
of new rules have been proposed under the Ports and Waterways Safety 
Act which further strengthen existing U.S. tanker safety law. They in- 
clude rules on navigation and safety (42 Fed. Reg. 5956, Jan. 31, 1977), 
personnel qualifications (42 Fed. Reg. 21190, Apr. 25, 1977), and on 
vessel designs, steering standards, segregated ballast, and inert gas 



330 

systems (42 Fed. Reg. 24868-24874, May 16, 1977). More recently, the 
Secretary of Transportation announced on Jan. 17, 1978 that if the Inter- 
governmental Maritime Consultative Organization meeting in March and 
June does not take any positive steps toward ratifying international 
tanker operation agreements, the United States will unilaterally impose 
its own agreements. The March meeting of the Intergovernmental Maritime 
Consultative Organization will focus on international requirements for 
ship design and the June meeting on crew training and qualifications. 

Through the promulgation of the above regulations and the announced 
intention by the Administration to strongly apply U.S. standards to foreign 
vessels, the provisions of existing U.S. law have been markedly strengthened. 

The issue of state regulation of vessel safety and design has great 
ramifications for the national energy transportation system. An underlying 
issue is whether or not states can regulate or interfere with the national 
transportation of energy — in this case with the type of tanker utilized. 
Will Federal laws preempt State requirements? Depending on the outcome 
of the Washington State case before the Supreme Court this term. Congressional 
involvement may be necessary. 

Several legislative proposals have been acted upon during the 1st 
Session of the 95th Congress which have a significant effect on the tanker 
safety issue. Comprehensive oil spill liability legislation (H.R. 6803) 
has been passed by the House and is now being seriously considered by 
both the Senate Commerce, Science and Transportation and Environment 
and Public Work Committees, which share jurisdiction over the legislation. 
Another proposal, the Tanker Safety Improvement Act (S. 682), has been 



331 



passed by the Senate and is now under consideration by the House of 
Representatives. It would legislatively mandate more stringent design 
and operational standards for all vessels in U.S. waters. 

Tied in with the tanker safety issue are a number of broader merchant 
marine issues including cargo preference, ship subsidy and tax issues, 
which will undoubtedly require congressional attention during the remainder 
of the 95th Congress. For now, tanker safety and design remains an issue 
even though a number of inroads have been made through the regulatory 
process. So long as a growing portion of U.S. oil is imported on larger 
and larger tankers in a more complex system and pattern of movements, 
Congress will continue to be confronted with the challenge of mating 
certain that this impact to the national energy transportation system 
is made in a safe and stable manner. 



References 

U.S. General Accounting Office. Vessel Control - What is Needed to Prevent 
and Reduce Vessel Accidents? .General Accounting Office, Jan. 21, 1075. 
24 p. 

U.S. Congress. House. Committee on Government Operations. Subcommittee on 
Government Activities and Transportation. Coast Guard Efforts to 
Prevent Oil Pollution Caused by Tankers. Hearings, 95th Cognress, 
Ist Session. March 21, and 23 1977. Washington, U.S. Govt. Print. 
Off. 1977. 551. p. 

.Committee on Merchant Marine and Fisheries. Subcomi- 

mittee om Coast Guard and Navigation. Oil Pollution Liability. Hearings, 
95th Congress, 1st Session. Feb. 24, 25; March 10, 23, 1977. Washington, 
U.S. Govt. Print. Off., 1977. 217 p. 

^_ . Office of Technology Assessment. Oil Transportation 

by Tankers: An Analysis of Marine Pollution and Safety Measures. Washingt 
U.S. Govt. Print. Off., July 1975. 288 p. 

U.S. Congress. Senate. Committee on Commerce, Science and Transportation. 
Recent Tanker Accidents. Hearings, 95th Congress, 1st Session. 
Jan. 11 and 12, 1977. Part 1. Washington, U.S. Govt. Print. Of foe. 
1977. 1-497 p. 



332 



. Recent Tankers Accidents: Legislation for Improved 

Tanker Safety. Hearings, 95th Congress, 1st Session. March 8, 15, 16 
and 18th, 1977. Part 2. Washington, U.S. Govt. Print. Off. 1977. 
500-1027 p. 

. Tanker Safety in Alaska. Hearings, 95th Congress. 

1st Session. April 28, 1977. Part 3. Washington, U.S. Govt. Print. 
Off., 1977. 1029-1113. p. 



333 



3.3.3. Transportation Requirements of the Strategic Petroleum Reserve * / 

Much of the interest to date in the Strategic Petroleum Reserve 
(SPR) has centered on establishing and filling it. Now that the Reserve 
has been established and is in the process of being filled, increased 
attention is being given to the transportation problems that would be 
associated with a drawdown of the Reserve in an emergency. Because the 
severity and duration of such an emergency cannot be known in advance, 
it is impossible to accurately predict the precise effect that it would 
have on the transportation system, but the general problems are well known. 

3.3.3.1. Background . The Federal Energy Administration (FEA) in 
its Regional Petroleum Reserve Reexamination of August 19, 1977, has 
indicated that the timeliness of implementation and the effectiveness 
of certain contingency measures and regulatory actions (such as the 
Mandatory Petroleum Allocation Program) would significantly affect the 
transportation requirements of the Reserve. The diversion of non-interrupted 
incoming shipments of petroleum to the East Coast, Caribbean, and West 
Coast refining centers and away from the Gulf Coast has been identified 
by the FEA as a key factor in the efficient distribution of oil from 
the SPR. FEA claimed that this diversion of shipping is desirable 
for three transportation-related reasons: (1) to reduce SPR crude oil 
shipments to the East Coast, Caribbean, and West Coast in favor of more 
efficient delivery to Gulf Coast and U.S. interior refineries; (2) to 
alleviate congestion at SPR ports inthe Gulf Coast; and (3) to facilitate 
a more rapid infusion of SPR oil into petroleum distribution systems. 

*/ Prepared by David M. Lindahl, Analyst, Environment and Natural 
Resources Policy Division. 



334 

A test of the International Energy Agency's allocation system in 1976 
showed that there is little incentive for refineries to divert shipments wi 
assurance of replacement supplies. FEA, therefore, has promoted an 
allocation program which could be implemented in time to provide this 
assurance along with additional backup authority that might be needed 
to deal with specific cases of noncompliance. FEA has stated that the 
degree of effectiveness of the Mandatory PeJtroleum Allocation Program 
and other regulatory actions will largely determine the level of shipping 
diversions achieved, which will directly affect the transportation re- 
quirements for SPR distribution. This might entail levels of diversions 
in response to a highly effective regulatory program that could approach 
100 percent of continuing Gulf Coast imports. A totally ineffective 
regulatory program, however, might result in little or no diversion. 

Another limitation that might limit the sizes of vessels that might 
be employed for carrying SPR oil is the physical characteristics of the 
loading and unloading ports that would be affected in SPR distribution. 
These characteristics include depth and width of channel, dock sizes and 
depths-alongside at the terminals, and the existence or non-existence of 
ballast treatment facilities at the loading terminals. Most of the Gulf 
ports (including the SPR ports) and the East Coast ports are physically 
limited to maximum vessel sizes of 35,000 to 50,000 dead-weight tons (dwt), 
although lightly loaded vessels of 80,000 dwt can enter some of these 
terminals and some 90,000 dwt tankers currently carry residual fuel oil 
from the Virgin Islands to the U.S. East Coast by lightering offshore. 

FEA has estimated, however, that the distribution of the SPR will be 
limited to the use of tankers of less than 50,000 dwt to 80,000 dwt. FEA 



335 

has also observed that the tanker terminals envisioned for use as SPR 
loading facilities presently do not have ballast treatment facilities, 
without which tankers will not be able to discharge ballast prior to 
loading SPR oil, thus reducing cargo capability. This is expected to 
increase tanker requirements for SPR distribution. 

Some improvement of port facilities is feasible through construction 
of additional terminal handling facilities such as docks and ballast treat- 
ment plants. Such improvements would probably be needed to accommodate the 
anticipated SPR drawdown rates. 

The Maritime Administration has concluded that in the most optimistic 
circumstances the total drawdown rates for each SPR source area would re- 
flect proportional increases for 150-day drawdown rates to achieve the 
approximately 4,700,000 b/d combined requirements. In that case, all of 
the 1,857,000 b/d of uninterrrupted imports to the Gulf Coast were assumed 
to be diverted to fully replace shortfalls on the East Coast, Puerto Rico, 
Virgin Islands, and West Coast and to partially replace supplies lost to 
other countries in the Caribbean. Extensive use of pipelines and short- 
distance waterborne carriage to distribute the reserve would be made pos- 
sible by the diversion of continuing shipments from the Gulf Coast to 
other regions. The tanker requirements calculated by the Maritime Admin- 
istration total approximately 1,370,000 dwt , more than half of which is for 
local Gulf Coast distribution which could be partially handled by barge 
shipment s . 

A pessimistic case was also developed in which it was assumed that 
there would be no diversion of continuing Gulf Coast imports, which would 
continue to go to their original refinery destinations thus reducing the 
demand for pipelines and local waterborne transportation. On this basis, 



336 

the FEA concluded that the lack of diversions would make necessary the 
replacement of regional supplies directly from the SPR. The FEA decided, 
therefore, that the lack of diversions would create extensive medium and 
long-distance requirements for distributing the SPR by sea and would 
create significant congestion at SPR ports. The Maritime Administration 
calculated that shipping requirements for the pessimistic distribution 
scenario would exceed 5,700,000 dwt , of which only seven percent is for 
local Gulf Coast distribution that could be met with barges to reduce 
the overall requirement. 

3.3.3.2. Tanker Availability . The problem of transportation avail- 
ability for distribution of the SPR, therefore, is primarily one of 
tanker availability. Even though a substantial part of the SPR would 
be transported by pipeline, most of the SPR traffic through the pipelines 
would consist of a restoration of business-as-usual flows. The relatively 
minor and isolated cases where modification of normal pipeline flow 
patterns might be necessary for SPR distribution could probably be anticipated 

and arrangements made. Tanker availability, however, would be much more 

1/ 

uncertain and would depend on several highly variable factors. 

Section 27 of the Merchant Marine Act of 1920, known as the Jones 
Act, prohibits foreign-flag vessels from carrying domestic cargoes. It 
is not yet clear, however, whether or not the Jones Act would apply to 
shipments of SPR crude oil to foreign Caribbean refineries and to subse- 
quent shipments of refined products to the United States. In any case, 
it is apparent that U.S. flag vessels will be required for most waterborne 
distribution of the SPR. Because most Jones Act tankers are already 

II Federal Energy Administration. Regional Petroleum Reserve Reexamination, 
August 19, 1977, p. Ill, 15-24. 



337 

committed to existing traffic, this restriction would effectively limit 
SPR shipping to U.S. tankers not currently in domestic service. In 
situations where not enough U.S. flag vessels are available, however, 
it may be necessary to waive the Jones Act requirement that only U.S. flag 
ships may participate in the carriage of domestic cargoes. The Secretary 
of Treasury has the authority to waive the Jones Act, "... if necessary 
in the interest of national defense to permit the use of foreign 

flag vessels in domestic trade. The national defense need would not be 
difficult to prove, and such a finding would probably be made which would 
automatically link national defense considerations to the drawdown of the 
SPR. This would greatly expedite the waiver process, but the procedural 
details at the Federal Maritime Administration have yet to be clearly 
established and incorporated into appropriate contingency plans for im- 
mediate implementation during a crisis that would require an SPR draw- 
down . 

Presently, owners of vessels built with construction and operating 
differential subsidies (CDS and ODS) are not allowed to operate their 
vessels in strictly domestic commerce. If these ships were needed for 
SPR distribution, however, permission for them to participate could prob- 
ably be easily obtained, although these procedures have not been clearly 
established either. 

Substantial tonnages of foreign-flag shipping are likely to be readily 
available if needed to distribute the SPR. The FEA estimated that as 
much as 25 million dwt of shipping would be idled in or near U.S. waters 
during the supply interruption and would be seeking employment. If adequate 

24-786 O - 78 - 23 



338 

shipping was still unavailable, however unlikely, American -owned foreign- 
flag vessels could be made available for SPR service under the provisions 
of the Merchant Marine Act of 1936. This would require a declaration of 
a national emergency by the President and would be administered by the 
Secretary of Commerce. According to the FEA, there are approximately 326 
ships, representing more than 36 million dwt , that would be subject to this 
Act. Tanker availability is unlikely to be so critical that the Act 
will need to be used, but the FEA has recommended that it be included in 
the appropriate contingency plans. 

Ship characteristics, such as size, registry, age, and cargo type, 
will also be important factors in determining the availability of SPR 
tankers. Because of the relatively shallow depths of most SPR ports, 
SPR vessels will be limited to those that have drafts low enough to enter 
the harbors. The relatively short transit distances that would be involved 
in an SPR distribution would make lightering to larger tankers offshore 
impractical. Draft limitations at SPR ports would permit the use of tankers 

of up to 35,000 dwt for Freeport and up to 80,000 dwt (light-loaded) for 
2/ 

St. James. Because most of these ships are already employed in normal 

domestic service, they may be in short supply when needed for SPR distri- 
bution. Many of the small foreign tankers presently engaged in lightering 
and shuttle operations along U.S. coasts could probably be made available 
for SPR distribution if needed. (For related information on U.S. tanker 
availability, see 3.1.14.) 

II Ibid . , p. III-20. 



339 

Vessel registry is a factor because the Jones Act limits domestic 
trade to ships registered in the United States, Consequently, it is certain 
that the tankers that would first participate in the SPR distribution would 
be U.S. -flag vessels. If domestic shipping were not available in adequati 
amounts, then it may be possible for foreign-flag vessels to obtain Jones 
Act waivers. 

Vessel age is a major disadvantage of the U.S. tanker fleet. The FEA 
has noted that approximately half of the current U.S. -flag tanker fleet 
is more than 20 years old and that most of these are of the size needed for 
the movement of SPR oil. However, most of the scheduled new tanker 
construction is for vessels too large and ill-suited for operation in Gulf 
and East Coast ports. As older ships are retired from service, therefore, 
the number of U.S. -flag ships appropriate for SPR distribution will drop. 
This is not expected to occur to a large degree before 1985, and foreign- 
flag tankers will probably continue to be available in substantial numbers 
after that year. 

Cargo type may become a factor if SPR distribution to foreign Caribbean 
refineries is ruled to be subject to the Jones Act. Additional domestic 
tankers would be needed, therefore, to replace foreign-flag vessels cur- 
rently serving U.S. markets from Caribbeans refineries. To the extent 
that petroleum products are stored, specific types of tankers might be 
needed. The FEA reported that as of June 1976, 70 percent of the U.S. 
flag tankers were on clean voyages, 75 percent of the U.S. tankers had fully 

coated tanks, 7 percent had partly coated tanks, and the remaining 18 percent 
3/ 

were uncoated. Some of the available domestic tankers could therefore 
3/ Ibid. , p. III-21. 



340 

carry clean cargoes if needed during an SPR drawdown. If this proved 

insufficient, Jones Act waivers could probably be obtained for the use 

of foreign tankers normally operating in the Caribbean. 

The trade routes of existing tanker traffic will be a major determinant 

of the availability of shipping for use in transporting oil from the SPR. 

The FEA assumed that U.S. vessels would not be diverted to other domestic 

4/ 

trade, including Alaskan, to serve SPR needs. As a result, the ships 
that will be available will consist primarily of domestic ships either 
"laid-up" or engaged in foreign trade. The use of Jones Act tankers in 
the Alaskan trade could greatly reduce the number of such ships available 
for SPR distribution. If a transcontinental pipeline is built to provide 
a means of moving surplus Alaskan oil eastward, the need to transport Alaskan 
oil by tanker through the Panama Canal to the Gulf Coast would be eliminated, 
thereby freeing more Jones Act tankers for SPR use. Even though economics 
would probably make available ODS and CDS tanker capacity during an 
interruption, most of these U.S. ships could experience some delays in 
being disengaged from current trade and in being redirected to SPR traffic 
from normal routes. Once cargoes in transit were delivered, the actual 
time needed to reach SPR ports would be relatively short. 

Existing terminal facilities would probably be unable to handle SPR 
tanker traffic unless non-interrupted imports were diverted from Gulf Coast 
ports to other regions. If substantial diversion did not occur, the FEA 
predicted that terminal-handling problems and distribution bottlenecks would 



4/ Ibid. , p. III-21. 



341 

5/ 

take place. The timing and extent of shipping diversions would be 
directly related to the speed of implementation and the effectiveness 
of the Mandatory Petroleum Allocation Program. The FEA noted that al- 
though shipping diversions could be required under the Magnuson Act or 
the Defense Production Act, allocation programs developed under the 
Emergency Petroleum Allocation Act and the Energy Policy and Conserva- 
tion Act . 

The availability of large amounts of tanker tonnage does not appear 

to be a problem in the foreseeable future. Even though large quantities 

of U.S. -owned tankers are registered under flags of convenience, the FEA 

considered them sufficiently reliable to meet the needs of the U.S. Govern- 
6/ 

ment . The operational control exercised by the U.S. owners of these 
vessels would be more significant than the nominal political and legal 
control of the countries to which they are registered. 

Ships of U.S. registry would clearly be preferred for SPR distribution. 
As many as 60 vessels of 80,000 dwt or less and totalling approximately 
2.3 million dwt may be available through 1980 for SPR use. Nearly two- 
thirds of this tonnage (1,515 million dwt) could be used to carry refined 
petroleum products as well as crude oil. This would probably be adequate 
to replace foreign-flag carriers between Caribbean refineries and U.S. 
ports. In its range of forecasts, the FEA optimistically predicted the 
need for approximately 1,370 million dwt of shipping, nearly all of which 
could be met with U.S. -flag tankers. FEA's pessimistic scenario, however, 

2/ Ibid . , III-23. 
6/ Ibid., III-24. 



342 

projected a demand for almost 5,700 million dwt of capacity, which could 
certainly not be satisfied solely with ships of U.S. registry. The ship- 
ping tonnage that would be idled by another oil embargo of the United States 
alone could be greater than 25 million dwt, some of which would be foreign 
tankers in U.S. waters and therefore readily accessible. Much of the idled 
tonnage would be owned or controlled by U.S. companies and would be made 
available for SPR service between domestic ports through the requisitioning 
provisions of the Merchant Marine Act of 1936. Small tankers could be 
used for lightering oil to ships too large to directly serve all Gulf 
and East Coast ports. Cabotage restrictions would have to be waived, 
however, before the tankers could be used in this capacity. The Maritime 
Administration has stated that the maximum and minimum transit times 

for vessels to queue for withdrawal at the SPR ports would probably be 

7/ 

one to seven days. 



y Ibid. , p. III-26. 



343 

3.3.4. Oil Tanker Surplus */ 

Although the demand for U.S. -flag tankers is strong, largely because 

of the Alaskan oil surplus, the international tanker market has a large surplus 

of vessels. Despite occasional increases in demand, the tonnage in the laid- 

up fleet has for last several years been approximately 35 million deadweight 
1/ 

tons (dwt). The total world tanker surplus is estimated to be about 
85 million dwt, including the 35 million dwt in lay-up, 35 million dwt 
absorbed by slow steaming, and another 15 dwt through miscellaneous inef- 
ficiencies and combined carriers. 

The prospects for an improvement in the situation are not bright. 
Some estimates place the surplus by the end of 1977 at over 90 million dwt or 
even higher. Many tanker orders have been canceled or converted, but over 
30 million dwt are still being built with about 24 million dwt scheduled 
for delivery in 1977, but this may slip to around 20 million dwt. If 12.5 
million dwt are scrapped, a net 7.5 million dwt would be added to the 
existing fleet of 320 million dwt. Some orders are too near completion 
to make cancellation economically advantageous. The cancellation penalties 
would eliminate any potential savings on tankers due to be delivered be- 
fore 1978. Most of these orders were placed before 1975 when the market 
was stronger. Very few orders for tankers or combination carriers have 
been placed since then. 

The added capacity will very likely swell the current surplus of 
tankers and demand will probably not improve before 1980, especially if 
serious energy conservation programs are successful in reducing the 

*/ Prepared by David M. Lindahl, Analyst, Environment and Natural 
Resources Policy Division. 

y Ted Wett, Oil and Gas Journal , August 29, 1977, p. 21. 



344 

need for imported crude oil. The Oil and Gas Journal has identified 

four other factors that will also contribute to a decrease in tanker 

2/ 

demand, especially for very large crude carriers (VLCC's): 

— Production from the North Sea is expected to reach 1.3 million b/d 
this year. This is primarily short-haul oil moved by small to medium- 
sized tankers. It displaces long-haul imports moved by VLCC's. 

— Growing throughput through the trans-Alaska crude line will displace 
an equivalent volume of imports by the U.S. 

— A new 40-inch pipeline is in operation from Iraq through Turkey 
to Dortyol that will permit 500,000 b/d of Iraqi oil to be piped to the 
Mediterranean instead of being tankered around Africa from the Persian 
Gulf. 

— The Suez-Mediterranean Pipeline System shipped its first oil early 
this year and is expected to build up throughput toward its planned ultimate 
capacity of 1.6 million b/d. This cuts further into the long-haul traffic 
around the Cape of Good Hope. 

The world surplus of tankers could reach 100 million dwt by 1978. The 
surplus of VLCC's will be particularly acute and could last until the mid- 
1980s. If North Sea production reaches 7 million b/d, it could meet 40 
percent of European demand. That could reduce imports to Europe by 4 million 
b/d in ten years. 

Completion of the widening and deepening of the Suez Canal in 1980 will 
permit passage of ships up to 150,000 dwt. These ships may offload part 
of their cargo into the Sumed pipeline, reducing overall tanker demand 
even more. It could, however, increase the demand for larger vessels 
in preference to smaller ones. 

2/ Ibid. 



345 

Because of the tanker surplus, freight rates are well below profit- 
able levels. It is not unusual for a 200,000-dwt vessel making a single 
round-trip voyage from the Middle-East to Northwestern Europe during 
the first half of 1976 to receive only $4.26 per ton of cargo carried (26 
points of Worldscale) . On the same voyage, operating costs averaged about 
$5.59 per tons (34 points of Worldscale), producing a loss of $1.33 per 
ton. The main burden of the tanker surplus has fallen especially hard 
on the independent tanker owners who do not have long-term charters for 
their vessels. This surplus tonnage, in raid-1977, totaled 96 million dwt 
out of a total independent fleet of 196 million dwt. 

As a result, approximately $1.5 billion in tanker mortgage debt is 
currently in default. Ships without long-terra employment are carrying 
$2.7 billion of the $27 billion in world tanker debt. This could rise 
to $10 billion on unemployed tankers by 1980. There have been relatively 
few foreclosures to date because seizure of an asset that has less than 
50% of its original value does not generally appeal to mortgage holders. 
The lenders, however, are not likely to let defaulted loans continue 
indefinitely . 

One technique used to shrink the surplus is slow-steaming, a variable- 
speed voyage which reduces surplus tonnage and cuts bunkers fuel consumption 
by as much as 17 percent when a speed is reduced by two knots. A 200,000 
dwt tanker on a transoceanic voyage can save $112,000 by slow-steaming. 
Smaller ships can save even more proportionately because of their lower 
fuel consumption per ton of cargo. 

3/ Ibid. , p. 22 



346 

Lay-ups are not desirable over the long term and cannot usually be 
justified for periods of less than one year. In addition, the ship must 
be protected and maintained during the lay-up, and up to half of the normal 
deck and engine-room crew must remain on board. Reactivation is also ex- 
pensive, averaging between $750,000 and $1 million after a one-year lay-up. 
The amount increases with the length of the lay-up period. After a lay- 
up period of two to three years, many of the smaller, older tankers will 
probably not be able to compete economically again. 

In 1975, the International Maritime Industry Forum (IMIF), re- 
presenting shipbuilders, owners, charterers, and banks was established 
to study the issue of surplus tankers. The IMIF suggested accelerated 
scrapping programs, segregated ballast tanks in tankers over 70,000 dwt , 
adjustment of loadlines in order to reduce cargo capacity, and the use 

of tankers to store strategic supplies of oil near major importing 

4/ 

countries or to provide facilities for dirty ballast water. 

Few of the Forum's suggestions have been implemented. The United 
States and some European countries are reportedly considering segregated 
ballast tanks as an anti-pollution measure, but use of tankers for 
strategic petroleum storage is not likely since the decision was made 
to use salt domes as a less expensive but less convenient alternative. 
Japan, however, is engaging in such storage of strategic petroleum in 
tankers. The greatest difficulty experienced so far by the IMIF has been its 
failure to persuade the U.S. Justice Department to allow U.S. oil companies 
and banks to participate in industry-wide negotiations on the matter. 

4/ Ibid. , p. 22. 



347 

Scrapping may not be as effective as had been hoped. Demolition 

of less that one percent of the world's 1976 tankers of more than 150,000 

5/ 

dwt is expected in the next five years. These are the vessels that ac- 
count for most of the current surplus. More than 40 percent of the tankers 
under 70,000 dwt and over 18 percent between 70,000 aNd 150,000 dwt could be 
scrapped by 1981. Very few tankers over 100,000 dwt have been scrapped 
and even fewer of the 150,000 dwt type. All of the VLCC's are less than 
ten years old, and for them scrapping is not a viable option. 



5/ Ibid , p. 23. 



348 

3.3.5. Overseas Supply Line Vulnerability. */ 

Projections show the United States will need to import from 
overseas about ten to fifteen million barrels of petroleum per day 
(over half of total consumption) after 1980 until some indefinite 
future time, depending on the direction taken in setting national 
energy policy. The degree to which the Nation is becoming dependent 
on overseas energy supplies adds measurably to an already great 
dependence on shipping and ocean supply routes to obtain essential 
products, and prompts this inquiry into the safety of our ocean sup- 
ply lines. This section explores possible threats to ships engaged 
in the import of petroleum and the ability of the United States to 
defend against them. 

In addition to interdiction at sea, U.S. overseas oil supply is 
also vulnerable to interruption at the source by politically or 
economically motivated embargo, sabotage or disruptions incident to 
regional conflicts, by denial of the use of foreign flag shipping 
on which we depend for much of our transport, and, at the U.S. 
terminals, by such impediments as strikes or restrictions on the offload 

of tankers in U.S. inland waters for environmental reasons. These 

2/ 

threats are beyond the scope of this chapter. 

*/Prepared by Alva M. Bowen Jr. Foreign Affairs and National Defense Division. 

_1/ . Includes Alaskan and Mexican oil which must come by sea from 
pipeline terminals. 

2/ A variety of threats to U.S. oil supplies are covered in detail 

in U.Si Congress. House. Oil Fields As Military Objectives: 
A Feasibility Study prepared for the Special Subcommitte on 
Investigations of the Committee on International Relations 
by the Congressional Research Service of the Library of Congress. 
(Committee Print). August, 1975. 



349 



3.5.5.1. Background . 

Table I shows projected petroleum imports for years of interest. 



TABLE I 

1/ 

PROJECTED OIL SHIPMENTS FROM OVERSEAS 
(thousands of barrels/day) 



SOURCE 


1977 


1980 


1985 


1990 


Alaska 




1,600 


2,000 


3,900 


South American/Caribbean 


1,300 


1 ,300 


1,250 


1,150 


Mexico 


150 


350 


700 


1,250 


West Africa 


1,200 


1,150 


1,200 


1,250 


Mediterranean (North Africa) 


1,000 


1,150 


1,200 


1,200 


Western Europe 




100 


500 


500 


Indonesia/Southeast Asia 


630 


810 


850 


950 


Persian Gulf 


3,655 


5,485 


6,100 


6,600 


TOTALS 


7,945 


11,945 


13,800 


16,800 



1^/ Source: U.S. Congress. Senate. Committee on Commerce, Science and Trans- 
portation. The National Ocean Policy Study, and House. Committee on 
Interstate & Foreign Commerce. Subcommitee on Energy & Power. Project 
Independence: U.S and World Energy Outlook Through 1990. A Summary 
Report prepared by the Congressional Research Service of the Library 
of Congress. June 1977. (Committee Print; publication No 95-31). p. 50. 



350 

Table II shows the approximate number of hypothetical 80,000 dwt 
tankers that must be at sea on the routes indicated to maintain these 
imports. Chart I portrays these routes graphically. 

TABLE II 



Tankers at Sea to Meet Overseas Oil Shipment Projections 



PASSAGE 



1977 



1980 



1985 



1990 



Alaska-U.S. West and Gulf Coasts — 

South America/Caribbean - U.S. 

East Coast 22 

Mexico - U.S. Gulf Coast 1 

West Africa - U.S. Gulf Coast 65 

Mediterranean - U.S. East Coast 40 

Western Europe - U.S. East Coast — 

Indonesia/Southeast Asia - U.S. 

West Coasts 45 

Persian Gulf - U.S. East and Gulf 

Coasts 404 



41 

22 

2 
62 
46 

3 

58 

604 



72 

21 
3 
65 
48 
15 

61 

672 



140 

19 
5 
67 
48 
15 

68 

727 



TOTALS 577 838 957 1089 

% of totals on Persian Gulf route 70 72.0 70.2 66.8 

In addition, from 80 to 100 coastal tankers will be engaged in 
the movement by sea of refined petroleum products from U.S. Gulf Coast 
to East Coast ports. Maps and #10 of the series of maps appended to 
volume I of the study indicate the coastal routes involved. 

As may be seen from Table II the route from the Persian Gulf 
by way of the Cape of Good Hope accounts for well over two thirds 
of the ships. By 1980 there must be an average of one 80,000 dwt tanker 



352 

coming or going every 20 miles along that route to meet projected 
U.S. demand. The routes along the northeast coast of South America 
and in the Gulf of Mexico will experience the densest traffic. 

Insuring the safe and timely arrival of this volume of ship- 
ping in peacetime is mostly a matter of seamanship, organization 
and good management of assets. In times of war or tension, necessary 
protective measures add a new dimension to the task. Hostile action 
against shipping can range from harassment, through visit and search, 
to seizure or sinking, and from local incidents to all out attacks 
along the sea lanes. Interference or closure can be enforced by either 
fixed or semi-permanent means such as shore batteries or sea mines, 
or by mobile units (air or water craft). 

The possibility of unacceptable retaliatory action, not necessarily 
by military means, has traditionally been the most effective deterrent 
to hostile action against shipping in peacetime, and this deterrence 
is apparently effective today, potentially hostile powers having been 
given a demonstration of U.S. retaliatory capability incident to the 
Mayaguez affair in 1975. Should deterrence fail, providing protection 
for the large numbers of ships involved could become a difficult and 
costly task, depending on which routes were threatened and to what extent. 



353 

Countermeasures to hostile actions against shipping include evasive 
routing, arming the ships, sailing them in company with armed escorts, 
and preventing access by hostile forces to the shipping lanes. Sailing 
ships in convoys to facilitiate protection has been effective in reducing 
losses even when armed escorts are unavailable or not available in 
sufficient numbers. In practice, all of these measures are usually 
used to some extent to oppose an active interdiction effort. 

3.3.5.2. Analysis . 

A capability to threaten an oil route requires forces and position 

from which force can be applied. The Soviet Union or a coalition 

of our European allies would be capable of strategic (global) interdiction 

2/ 

of U.S. oil imports. Certain other countries have the capability 
to interdict nearby routes. The threat of local interdiction will 
be examined first, followed by an analysis of the threat of strategic 
interdiction . 

Several countries have the capability to threaten a nearby oil 
route. India, Iran, Pakistan and the Union of South Africa are in 
position and have the forces to interdict Indian Ocean routes. Brazil 
can interfere with routes from the Persian Gulf and West Africa, which 



y Edwin Potter and Chester Nimitz. The Great Sea War. New York: 
~ Bramhall House, 1960. p. 71. 

2/ Ppssibility that our allies would threaten our oil routes is so 
remote that it will not be considered further. 



24-7B6 O - 78 - 24 



354 

pass near her northeast coast. Cuba lies across these same routes 
as they approach their Gulf Coast terminals, and can also jeopardize 
Panama Canal oil traffic and the inter-coastal shipping from the 
Gulf of Mexico to the Atlantic seaboard. Canada has the position and 
the forces to interfere with the Alaskan oil route, and Japan and 
Australia could attack shipping from Indonesia. Oil from the 
Mediterranean could be subject to interruption throughout most 
of its voyage within the Mediterranean by various powers, and after 
it leaves the Mediterranean by forces based on the Azores, Madeira 
or the Cape Verde Islands (which also lie near the West African 
route). This assessment ignores the present political alignment 
of these countries, and speaks only to their capabilities. However, 
the likelihood that any of them would attempt to exercise their 
capability against the United States is almost non-existent. All 
are allied with the United States or are deterred by other political 
considerations. None could expect to unilaterally challenge a 
superpower without suffering unacceptable retaliation. A scenario 
could be written wherein one of these countries became a surrogate 
for the Soviet Union and undertook maritime interdiction operations 
under her protection, but even that highly unlikely scenario would 
place the attacker in hopeless competition against the preponderant 
power of the U.S. Navy and Air Force. 

Other countries flanking the oil routes do not have the forces 
to conduct sustained interdiction operations, and if they obtained them 
would be subject to these same considerations. The rjost economical 



355 

interdiction measure, use of sea mines to effect one-time closure 
of a restricted waterway, could cause a temporary disruption, but 
mines are subject to clearance operations which could re-open the 
waterway, and the likelihoodof superpower retaliation should deter 
the use of sea mines by small nations. This leads to the conclu- 
sion that no nation-state other than the Soviet Union is likely to 
threaten armed attack on oil shipping engaged in supplying imports 
to the United States other than, perhaps, as an isolated incident 
such as the Mayaguez affair in 1975. 

A more likely threat to seaborne oil traffic is the possibility 
of terrorist activity by any one of several sub-national groups. Th« 
likelihood that a sustained terrorist campaign could destroy enough 
ships to interdict a route is low, but total security against such 
attacks would be very difficult to achieve. The terrorist objective 
would more than likely be psychological and political rather than 
strategic interdiction of the oil route. Uncertainties created by 
a series of successful attacks on tankers could adversely affect 
insurance rates, and cause diversions and disruptions of- scheduled 
sailings, thus reducing the efficiency of the oil distribution 
system. Terrorist attacks on oil tankers would require favorable 
positions from which interception can be initiated and preferably 
a nearby permissive host nation for post attack sanctuary. 



356 

Countering isolated terrorist attacks on shipping can best be handled 
on a case by case basis. The Mayaguez affair provided one example, 
probably at the high end of the violence scale, of a response to a 
particular situation. Destruction, rather than capture of the vessel, 
would have called for a different reaction. More extensive measures would 
be required if the incidents showed a pattern indicating they were not 
isolated. Any of the various protective measures mentioned earlier 
might be appropriate, depending on the extent of the route threatened 
by terrorist attack, the frequency of the incidents, and whether the 
attacks were being made on oil traffic generally or only on U.S. shipping. 
Suppression of a well defined terrorist campaign, even a campaign conducte 
from a sanctuary, would require operations similar to those conducted in 
the suppression of piracy, which terrorism resembles. These operations 
would not severely tax U.S. naval capability in peacetime, but they might 
be costly if the United States were the only nation involved in policing 
the oil routes. 

The only power capable of strategic interdiction of U.S. oil 
imports and not an ally is the Soviet Union. Only that nation has 
the global basing system and the air and naval forces that would be 
required. Some hold that Soviet attack on the U.S. oil routes is 
only likely in context of a superpower war in which their European 
allies would also participate. Involvement of Asian allies in the 
opening phases of such a war might or might not occur. Others believe 
a Soviet attack on U.S. oil routes is possible without European involve- 
ment. Both possibilities will be examined. 



357 

3.3.5.3. NATO War . 

Navy response to the NATO war contingency involves re-supplying 
NATO ground and land based air forces from the United States, delivering 
a marine amphibious force to Europe and insuring the safe and timely 
arrival of shipping to keep the war effort going at home and in Europe 
(including a sufficient oil supply). There is evidence the Soviet Union 
would attempt to cut oil supply lines in the event of a NATO/Warsaw Pact 
War, and t^at NATO planning gives low priority to oil route protection. 

Study of Soviet exercise OKEAN 75 indicates a collateral interdiction 
effort against Middle East oil might be a part of an initial high intensity 
battle for Europe. Soviet capabilities against the oil routes displayed 
during OKEAN 75 consisted of land based aircraft operating from Conakry, 
Guinea; Havana, Cuba; Hargeisa, Somalia; Aden, South Yemen; and Soviet 
bases in Siberia . The aircraft supported ships and submarines, all coor- 
dinated by a sophisticated satellite surveillance system and a world wide 
command and control network. These forces operated off the east and 
west coasts of Africa, in the Caribbean, and along the oil route to 
Japan north of the Phillippines (Chart 2). Soviet statements concerning the 

excercise clearly indicated that the forces were practicing current 
1/ 

missions . 
1 



1/ William H. J. Manthorpe, The Soviet Navy in 1975, U.S. Naval Institute 
Proceedings Vol. 102 No. 879, May 1976. p. 205-212. 



358 



Chart 2 




NATO planning for this contingency is indicated by the following 

from the FY 1978 posture statement of the Chairman of the (U.S.) JCS: 

Since the founding of NATO, we have proceeded on the 
assumption that the NATO Alliance would be able to 
control and use the high seas. Up to the present, we 
have planned on the ability to carry out the full range 
of assigned tasks. These tasks include conducting sea 
control operations, containment of Soviet ballistic 
missile and attack submarines, countering Soviet surface/ 
air forces, protecting the transit of high value task 
groups, including amphibious forces, and strategic 
reserves, defending the strategic island bases, and 
finally protecting transit lines so that merchant 
shipping can deliver military and economic cargo. Since 
there are insufficient forces to plan on accomplishing 
these missions simultaneously, we will establish 
priorities and allocate forces to accomplish tasks 
according to Soviet capabilities and courses of action. 
It is clear that if the Soviet Union makes a maximum 
effort to interdict the Atlantic sea line of communica- 
tion and is able to predeploy a large portion of its 
submarines, there will be heavy attrition to early 
reinforcement and supply elements. 

'...The conventional force capability on balance is 
eroding, especially in the context of the early 
reinforcement strategy for NATO in a general war. 
All assigned missions cannot be accomplished simul- 



1/ Source: U.S. Naval Institute Proceedings Vol. 102 No. 881, July 
1976. p. 94. 



359 

taneously and will have to be prioritized .. .j^/ 

Since the resupply effort to NATO Europe is the priority maritime 

task during the initial battle, considerable portions of the sea control 

forces of the allies and the sea denial forces of the Warsaw pact forces 

will probably be committed to a "Battle of the Atlantic" whose outcome 

according to the Chief of Naval Operations would probably be favorable to 

the United States "by a slim margin." NATO strategy for the battle would 
2/ 

be: 

a. Seeking out and destroying enemy forces in the Atlantic 
area; 

b. Interdiction of Soviet air sea routes from their northern 
bases into the Atlantic sea lines areas; 

c. Reinforcing important strategic islands; 

d. Close support of those critical cargo merchant vessels 
which must sail early. 

The CNO has tesitifed that U.S. Navy sea control forces would be able 

to carry out their tasks in the North Atlantic and Western Mediterranean, 

3/ 

and in the Eastern Pacific as far west as Hawaii and Alaska. The sea 
routes from the Persian Gulf to Europe and North America would be defended 
during this time by "blocking", that is by attempting to keep Soviet sea 
denial forces out of the area. The Sea of Japan and the Mediterranean 
would be untenable for a time, but eventually we should be able to fight 



1/ Brown, George S. United States Military Posture for FY 1978: Statement 
to the Congress 20, Jan. 1977. p. 53-54. 

2/ Ibid. , p. 54. 

_3/ U.S. Congress. House, Subcommittee of the Committee on Appropriations, 
Hearings, Department of Defense Appropriations for 1977 , Part VIII, 
94th Congress, 2nd Session, p. 109. 

hi U.S. Congress. Senate, Committee on Budget, Seminars, Service Chiefs 
on Defense Mission and Priorities, Sept. 18, 1975, Navy, Vol. 1, 
94th Congress, 1st Session, Committee Print., Jan 1976, p. 15. 



360 



1/ 

our way back into the Eastern Mediterranean. 

It thus appears that the Soviet Pacific Fleet would not have 
much opposition should it move into the Indian Ocean during the battle 
for the North Atlantic sea lanes, and that the Soviet Black Sea Fleet 
might gain access to the same region via the Eastern Mediterrean and 
Red Seas. A sizeable force could face NATO Allies along the Persian 
Gulf oil route when they are finally able to turn from the North 
Atlantic to more distant sea lanes. 

It is evident from these citations that U.S. planners do not 
accord defense of the oil routes high priority in the opening stages 
of a NATO war against the Warsaw Pact. There is reason to believe 
oil route interdiction operations are planned by the Soviet Union as 
an early effort in a NATO-Warsaw Pact war, and it appears their Pacific 
Fleet and possibly their Black Sea Fleet would be available to prose- 
cute interdiction operations. 

Although Admiral Holloway, the current Chief of Naval Operations » 

estimates the U.S. Navy could carry out its wartime missions "by a slim 

margin of success," his immediate predecessor as CNO, Admiral Elmo R. 

Zumwalt gave a less optimistic assessment. 

In November I gave you the range of estimates under a 
reasonable range of assumptions of my confidence in being 
able to prevail in a conventional war at sea with the 
Soviet Union. This range was from a little better than 
[deleted] at the present time. My personal estimates 
have been based on a review of enemy capabilities, a 
review of various analytical works that I have just 
summarized, insights from fleet exercises and consulta- 
tion with the senior commanders in the fleets. 

1/ Ibid., p. 13. 



361 



I have shown various comparisions of elements of naval capa- 
bilities and then referred to the results we obtained in analyzing 
various scenarios. The true measure of our capability can only 
finally be determined by fighting a war — anything short of that 
is judgmental. The closest we can practically come to measuring 
capability is in the results of our war games and fleet exercises. 
We know what these results and our professional judgement tells 
us will be the outcome , but we cannot be positive. However, 
we must put probabilities on our estimate to be of any use to 
the decisionmaking. With regard to these probabilities, I cannot 
be optimistic for the present when our fleet stands at its lowest 
levels in almost four decades. However, the present is a watershed 
year for the Navy. As you saw on the various graphic representations, 
our program of modernization for which we have sacrificed current 
capabilities is at the point where we will start to receive a 
payback. Under these circumstances, it is feasible we think 
to forecast a better confidence level of greater [deleted] in 
the 1980 time frame — if the budgets planned for 1975-78 are appro- 
priated. 1/ 

He later furnished the deleted figures in his memoir: 

I concluded with my annual estimate of the probability of victory 
in a non-nuclear naval war against the Soviets. In view of an 
adjuration by Jim Schlesinger to "be optimistic," I was glad 
to be able to say that this was the last year when our chance 
of winning would be as low as 30 percent — if Congress fully funded 
the Navy programs, that is. I said that given those programs — the 
Harpoon cruise missile, the F-14 plan, the Sea Control Ship, 
the Captor mine, the fourth nuclear carrier, and the rest of 
the major systems, high and low, new and old, previous chapters 
have described — the Navy would improve its capability year by 
year henceforward until, early in the eighties, its chances would 
be back beyond fiftyfifty again. 2/ 

Uncertainty in estimating the outcome of a battle for the sea lines of com- 
munication from the Persian Gulf stems from inability to estimate the affect attri- 
tion in the battle for the North Atlantic would have on the relative strength of 
the opposing sides, and whether the Southern Ocean' s claimon assets could await 
the outcome of that battle, which might last several months. 



\J U.S. Congress. House. Committee on Armed Services, Subcommittee on 

Seapower , Hearings on Military Rsture and H.R. 12564, Department 
of Defense Authorization for Appropriations, Fiscal Year 1975, Part 
2, 93rd Congress, second session, p. 995. 



2/ Elmo R. Zumwalt, ON WATCH: A Memoir. New York: New York Times Book 
Co. 1976. p. 464. 



362 

S.S.S. Axhe War at Sea Scenario . A variation of the NATO war in Europe scenario 
is the possibility that the NATO-Warsaw Pact conflict might be fought 
entirely or almost entirely as a war of attrition at sea, with sea- 

II 

fighting support installations the only permissible targets ashore. 
This variation is similar to the European war scenario previously 
discussed except that reinforcing NATO Europe might assume a 
lower priority if it became apparent that no attack on the central 
front was forthcoming. The defense of the oil routes would assume 
a correspondingly higher priority, with probably earlier application 
of naval and air assets to that task and some improvement to be expected 
in results. 

Mention was made earlier of the possibility that the Soviet 

Union might attack the oil routes without involving its Warsaw Pact 

allies. Unless the disruption selectively addressed only oil bound 

for U.S. consumption - a difficult task except near U.S. terminals 

- the result would probably be the the NATO war at sea previously 

discussed. Strategic interdiction of U.S. oil routes in the Carribean 

by Soviet forces based in Cuba would not interfere with supplies to 
2/ 

other countries. However, the likelihood of such a venture is considered 
to be remote because both the region and the oil supply are strongly linked 
to U.S. security interests and the Soviets could not rule out a nuclear 
response by the United States. 

_1/ An example of this variation is provided in Oilfields as Military 
Objectives, op. cit . p. 19-20. 

2/ The Caribbean example is almost unique in this regard. The other oil 
route that would involve only U.S. supply is the Alaskan Route, 
but the Soviet Union is not as well situated to easily threaten 
the Alaskan route. 



363 

3.3.5.5. Sunnnary, 

This review of oil route security indicates there is not much danger 
that single nations, acting unilaterally, would attempt to disrupt oil 
shipping. A terrorist campaign would possibly result in some disruption, 
but should not, in the long run, seriously affect deliveries. 

The most serious threat would come from the Soviet Union in event 
of NATO-Warsaw Pact war. The outcome of an oil route interdiction effort 
by the Soviet Union incident to such a war cannot be estimated with 
assurance, but it is apparent that NATO sea control forces would be 
severely tested by that contingency. Disruption leading to near stoppage 
of the Mid-East and possibly the Caribbean oil routes for several weeks 
is likely. Beyond that, there is a range of possible outcomes, none 
very well documented. 

In other than wartime situations instigated by the Soviet Union, 
perceptions by all relevant powers that the United States has the 
capability and the will to take appropriate retaliatory action if our 
sea routes are threatened is the most meaningful factor in assuring 
the safety of the oil routes. 



364 

3.3.6. Natural Gas from Mexico * / 

Major finds of natural gas in Mexico, associated with reserves of 
oil which may be second only to those of Saudi Arabia, have been discovered 
at a time when the well developed natural gas industry in the United States 
is suffering from declining domestic production. The Mexican Government 
is eager to sell the gas to U.S. pipelines who are equally eager to buy 
it. But an 800-mile pipeline is first required to bring the gas to the 
Texas border where the U.S. pipelines can pick it up. Approval of natural 
gas importation must come from the Department of Energy, which has shown 
reluctance based on the high price asked by the Mexicans. The substantial 
imports of gas being received from Canada are likely to go up to the same 
price level if the Mexican price is approved. Despite its potential, the 
import deal is currently in limbo for this reason. 

3.3.6.1. Background : On June 30, 1977, Petroleos Mexicanos (Pemex), 

the Mexican national oil company, announced that the proven reserves of 

oil in that nation had grown from 6.25 billion barrels to 14 billion barrel 

as a result of significant discoveries of oil in the Chiapas-Tabasco region 

Ten additional discoveries awaited definition as of September, 1977, with 

the belief by the Pemex General Exploration Manager, Ing . Santos Figueroa H 

1/ 

that reserves equal to those already found had been detected. Additional 
discoveries, strikingly similar in geological form, have been made on 
the continental shelf of the State of Campeche, about 100 miles north 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 

1/ Figueroa, Ing. Santos. J. Optimistic Mexican Oil Outlook Seen. Oil and 
Gas Journal, 9/19/77, p. 242. 



365 

of the first discoveries. Indications are that the entire huge shelf area 
may be a petroleum province of great richness because it is seen to be 
one geological unit. More than 100 structures which may bear hydrocarbons 
await the exploratory drill. Given these indications, preliminary 
estimates of the potential oil reserves of Mexico have ranged as high as 

120 billion barrels, more than three times the remaining proven oil reserves 

2/ 

of the United States. 

The gas-to-oil ratios of this production have been as much as 6,000 
or 7,000 parts to one. Vast gas reserves are thus assured, with perhaps 
even a greater energy content than the oil. The oil is already being 
exported to some extent, and further exports are planned. According to 
Pemex's General Exploration Manager, Mexico "will cooperate in satisfying 
world demand by selling its hydrocarbons and refined products without restric- 
tion to whoever adheres to accepted current commercial precepts." The 
latter phrase can only be interpreted to mean oil prices on a level with 
those set by OPEC. 

But natural gas is not as convenient to export as oil is. To be put 
aboard ship, it must be liquified at temperatures of 259 degrees below zero 
fahrenheit. This requires elaborate and expensive equipment, consumes a large 
portion of the gas, requires special vessels, has alleged safety problems, 
and has only a limited market at present. 

Pipelining the gas is cheaper, and Mexico is fortunate, at least 
in this instance, in having the United States as a neighbor. A fully developed 

Tj Figure attributed to Mexican Petroleum Institute. Piatt's Oilgram , 
October 28, 1977. 

V Op. Cit. Figueroa, p. 242. 



366 

market for natural gas has been created in the United States over fifty 
years, but has now outgrown its shrinking productive capacity. Little 
chance is seen of U.S. natural gas production rising again to the 
historical peaks it reached in 1973. U.S. pipelines and distributors 
are therefore seeking ways to meet demand, maintain their relative po- 
sitions against suppliers of other fuels, and continue to achieve a re- 
turn on their multi-billion dollar network of pipeline. Gasification of 
coal, importation of LNG from overseas, gasification of LPG and petroleum 
liquids, exotic sources of natural gas — all are being eagerly examined 
by the natural gas industry. 

Mexican gas discoveries at this time were therefore considered provi- 
dential. Six U.S. pipelines companies entered into negotiations with 

4/ 

Mexico to purchase the gas. But the gas would first have to be delivered 
to the U.S. border in a pipeline owned by Mexico and constructed by Mexicans, 
according to Mexican laws. 

This raised substantial problems of financing the pipeline. Since 
a 50% devaluation of the Peso in 1976, Mexico has had difficulty in bor- 
rowing on the international financial market. A credit limit of $3 billion 
had been established on top of the outstanding $20 billion in debts by the 
International Monetary Fund. The cost of the Chiapas gas pipelines, the first 
phase of which was estimated by Pemex at $990 million, is believed to cost 
in the range of $1.6 billion when completed. 



4/ The six companies are: Texas Eastern Transmission Corporation; Tenneco 
Inc.; Pacific Lighting Corporation; United Gas Pipeline Corporation; 
Transcontinental Gas Pipeline Corporation; and El Paso Natural Gas 
Company. All are regulated interstate pipeline companies except Pacific 
Lighting. 



367 

In July 1977, Pemex sought a loan from the International Monetary 
Fund and World Bank for pipeline construction costs, and despite a declaration 

by Secretary of Energy-designee Schlesinger that the U.S. would "be 

5/ 

responsive" if asked, Mexican officials made no request at that time 

for U.S. credit because of continuing obligations to the IMF. The IMF 
itself apparently could not loan the money. Furtures contracts with the 
six pipelines purchasers were looked at a possible means of financing the 
line, but also fell through. In addition, there was some talk in the 
Texas State legislature about providing State financing if the U.S. Govern- 
ment failed to make the deal possible. 

When the IMF reported it had no objections to such additional debt 
on Mexico's part, however, two loans totalling $550 million were negotiated 
with the U.S. Export-Import Bank. The loans would cover the the costs of 
purchasing U.S. pipe and pipeline supplies for the 48" diameter project. 
Added to $1.1 billion sought from other lenders, this loan would enable 
Pemex to construct the line. 

Construction had begun even as financing deals were pending, and at 
the end of September, 1977, Pemex announced that financing for the pipeline 
project was completed. Numerous international financial institutions had 
offered credit to the project because the collateral value of the natural 
gas and the relatively quick payback period of the loans. In addition 
to the Eximbank loan of $590 million at 8 1/2% for 8 years, Pemex landed 
other loans including a 100-million swiss franc bond issue at 5.75% for 10 years. 



5/ Quoted in Piatt's Oilgram, July 12, 1977 Vol. 55, No. 133, p. 2. 



368 

But even as construction of the gas pipeline began, criticisms arose 
on both sides of the border. In the United States, independent oilmen 
pointed to the proposed import price of $2.60 per Mcf, about $1.14 more per 
Mcf than Federal regulations currently permit U.S. producers to charge 
for sales to the same companies. Several independent oil groups planned 
to use the hearings at the Federal Energy Regulatory Commission on the 
import application as a forum to argue that they were being asked effecti- 
vely to subsidize imports, and should be able to receive the same price 
for the same commodity as the Mexican national company received. 

Taking the opposite tack, Senator Adlai Stevenson called for a lower 
import prices for the gas, and suggested that Eximbank financing be denied 
if Pemex was unwilling to lower its price terras, which were pegged to the 
delivered price of distillate fuel oil in New York harbor for the first 
six years of sales. The current equivalent price would be about $2.60 per 
thousand cubic feet (Mcf). Stevenson introduced a resolution disapproving 
of the deal, but had missed the 30-day deadline by which congressional 
disapproval had to be expr ssed to block the loans. 

Stevenson's comments added to pressure on Pemex in Mexico from political 
elements opposed to conditional U.S. financing and calling the pipeline 
"another Panama Canal." Pemex 's Director General Diaz Serrano was asked 
to testify before the Chamber of Deputies concerning the deal. Serrano 
testified that Mexico did not require U.S. financial assistance, would 
refuse it if it were tied to the export price, would not lower the price, 
and could sell the gas elsewhere, if necessary. He explained that the 
pipeline construction would halt 75 miles short of the U.S. border during 



369 

I 

the first phase, serving Mexican markets, until the U.S. buyers had official 
approval from the Federal Government to pay the asking prices. This testimony 
reportedly defused most of the opposition to the proposal. 

Despite rumors that negotiations had been broken off, official Mexican 
sources reported that the U.S. pipeline companies had been given until the 
end of 1977 to finalize arrangements. As late as December 1, 1977, 
President Portillo of Mexico reported that, as far as he knew, the loan 
was not blocked, and negotiations for the sale were continuing. 

Shortly thereafter, however, it was reported that Department of Energy 
Officials had intervened in the negotiations, seeking to lower the proposed 
price to $2.16, the current price of gas imported from Canada. The move 
was apparently prompted by fears, supported by reports from Ottawa, that 
if the U.S. were to pay $2.60 to the Mexicans for natural gas, the Canadian 
gas export price would be raised to the same level. This would mean a 
price increase of approximately $420 million for the almost one trillion 
cubic feet imported annually from north of the border, most of which would 
be on the West Coast. Despite the irritation of the pipelines involved, 
which had fully agreed to the price terms sought by Mexico, the reluctance 
of the U.S. Federal Government to approve the deal appeared to increase 
when no price flexibility was shown. 

On December 15, 1977, Senator Stevenson again argued that the prices 
were too high — that Petroleos Mexicanos would make ample profits at $1.75 

per Mcf, the proposed price for new domestic U.S. gas. He saw the Mexican 

7/ 

demand as asking for "foreign aid in the guise of gas prices." 

tl Piatt's Oilgram , December 9, 1977, p.l. 

y Congressional Record, Dec. 15, 1977, p. S. 19938. 

24-786 O - 78 - 25 



370 

The year-end deadline for completing negotiations expired without an 
agreement, with the Mexican and U.S. Governments holding to their price 
demands, and six pipeline companies trying to mediate. Shortly after 
negotiations broke down, Permex officials began to push for vigorous ex- 
pansion of gas sales in Mexico. Serrano Diaz was quoted as saying "we do 
not have to sell our gas abroad or flare it because we can sell it in the 
domestic market, replacing fuel oil ... that we can sell abroad for more 
than is now being paid." The six pipelines were given official notification 
that the negotiations were over. 

Vice President Mondale discussed natural gas with the Mexicans on a 

State visit in January, but no progress on the import deal was attempted 

or achieved. In addition, California Governor Jerry Brown has indicated 

to Mexico that a gas pipeline to his State would be supported, tapping 

t 

the Baja California deposits, but this purchase would also require 
U.S. Government approval. 

3.3.6.2. Gas Supply Contribution . The amount of natural gas being discussed 
between the pipelines and Mexico would begin at a level of 800,000 Mcf 
per day in 1979, delivered to Texas by the natural formation pressure 
of the Chiapas wells 800 miles away, and from some of the closer Monclova 
reserves. The addition of 750,000 horsepower of compression would boost 
the total deliveries by 1981 to about two billion cubic feet per day. 
This amount would represent about 5% of U.S. consumption, and would be 
the largest new supplement to declining U.S. natural gas production of any 
now planned. 

8/ Piatt's Oilgram, Sept. 2, 1977 , p. 3. 



371 

Yet additional Mexican gas would be almost certain to follow. Further 
exploration of the South Mexico fields appears likely to boost gas avail- 
ability to levels greater than could be absorbed by both the initial pipeline 
and Mexico's own ambitious gas consumption goals for petrochemical manufacture. 

Diaz Serrano, Pemex Director General, said in early September that by 1982 

9/ 

the pipeline would be too small too handle the available production. Ad- 
ditional significant natural gas fields in Mexico have been located in 
Northern Mexico near Monclova, and on the Baja California penninsula, 
both of which are expected to produce exportable volumes. The Chiapas 
pipeline may be only the beginning of large scale Mexican natural gas 
imports, and only the first of several pipelines, on the Pacific Coast 
as well as the Gulf Coast region. 

3.3.6.3. Price. The price asked for the Mexican natural gas may 
put it at a disadvantage in some U.S. markets. Unfortunately, and partly 
in response to U.S. pressures, the Pemex management is now so firmly on 
the record as insisting on the initially agreed to price of the equivalent 
of #2 distillate fuel delivered to New York that any flexibility on their 
side may now be politically impossible in Mexico. The political left in 
Mexico, opposed to any sales to the U.S. at first, are totally unwilling 
to settle for a lower price. The Government of Mexico has completely 
committed itself to those terms. 

The bargaining power of Pemex derives from their belief that U.S. 
consumers are in desperate need of natural gas, and that U.S. pipeline suppliers 
have been willing to arrange for gas from other sources at prices as high 

9/ Ibid., p. 3. 



372 

as $4.50 delivered, Alaska natural gas will clearly cost more than $2.60 
and possibly as much as $5.35 when delivered to distribution companies, 
and even then will be unavailable until the mid-eighties. But a crucial 
factor is that the Mexican gas price is at the border. At least $1.00, 
on the average, in pipeline charges must still be paid before that gas 
can be delivered to consumers at the far end of the purchasing pipeline 
systems . 

It is clear that under the price terms agreed upon by the pipelines, 
Mexican gas reaching the New York area would be unable to compete with 
the distillate fuel oil which is to serve as the marker for its price 
— unless the gas price was rolled in with ongoing supplies of lower 
priced domestic gas. This latter issue of rolled-in versus incremental 
pricing is being looked at carefully with respect to LNG and even new 
natural gas. Both Houses of Congress have approved an incremental pricing 
approach for domestic new natural gas sales, and Secretary Schlesinger 
has been quoted as tentatively favoring incremental pricing for LNG projects. 

If the Mexican gas is required to be sold incrementally, it may not 
be saleable at all, because even intrastate natural gas prices are still 
below $2.00 on the average and other fuels will also be competitive. 

The United States, however, is not without its own bargaining power. 
Its primary lever is that, practically speaking, Mexico has no other 
market for its gas besides the U.S. LNG exports are technically possible, 
but would require much additional time and capital and would, by virtue 
of the increased transportation cost component, force the Mexicans to 
accept a lower wellhead price. Pending completion of LNG exports facil- 
ities, some gas might have to be flared, a dead loss to the Mexican 



373 

Government. Analyses here have indicated that Mexican threats to use gas 

themselves, displacing oil which could be exported, are largely bluff — 

10/ 

it would take years to effect the necessary conversions. The Mexican 

Government would make much more money in selling the gas to the U.S. at 
$1.75 than to Mexican industries at a much lower price, offsetting any 
profit from the oil exports. 

The political problem in the United States posed by the domestic 
producers unable to charge an equal amount for natural gas may prove 
significant, even though a fair portion of the $2.60 per Mcf, perhaps 
as much as $0.75, can be attributed to the actual costs of the pipeline, 
bringing the wellhead price down to the level received by American pro- 
ducers in intrastate commerce, or in emergency sales in interstate com- 
merce . 

The U.S. case is also improved by the better domestic gas supply 
situation that has prevailed during the 1977-78 heating season. The basic 
Mexican assumption that U.S. buyers would be desesperate enough to pay 
the price asked for the gas may prove true in later years, but is not the 
case currently. The U.S. position is essentially drawn from a belief 
that the benefit of additional gas supply from Mexico does not outweigh 
the cost of having Canadian imports rise equally in price and having 
domestic producers perceive themselves as even greater victims of unfair 
Federal pricing policies. 

The determination of U.S. authorities to hold to the $2.16 price offer 
may not be as firm as that of the Mexicans to hold to their $2.60 demand, 

10 / The Energy Daily, "Gas Companies Scramble to Salvage Mexican Gas," 
January 5, 1978, p. 1. 



374 

however. First, the Canadian gas price will be raised sometime in 1978, 
and the probable level of increase will bring that gas to a price of about 
$2.40. In addition, ongoing negotiations in Congress over domestic gas 
pricing may yield a new domestic price much higher than $1.75, with escala- 
tions that would further bring the price up toward the Mexican price level 
by the time Mexican gas would begin flowing in quantity. 

Despite the current U.S. interest in arriving at a different price, 
the final price will almost certainly be $2.60 per Mcf because of the 
degree to which the Mexican authorities have been compelled to protect 
themselves from an image of bending to American economic power. 

3.3.6.4. U.S. -Mexican Relations . This brings up a major consideration 

of natural gas exports between the U.S. and Mexico: The proposed commerce 

in natural gas has the potential to better or worsen U.S. -Mexican relations, 

but almost certainly will not leave them unchanged. As the major investor 

in, exporter to, and creditor of the Mexican economy, the United States 

can begin by buying natural gas to improve the economic balance between 

the two nations. Obtaining dollars for natural gas will reduce the pressure 

on Mexico to obtain dollars in other ways, including remittances from 

Mexicans working in the United States. The question of illegal immigration 

may thus be addressed more workably with a more salutory impact on relations 

after the natural gas is flowing. Mexico will also be deriving additional 

revenues with which to engage in large scale efforts to create jobs and 

industry which can alleviate some of the poverty which has driven young 

11/ 

Mexicans across the border seeking work. 

11 / See Fagen, Richard R. The Realities of U.S. Mexican Relations. 
Foreign Affairs . July, 1977, pp. 685-700. 



375 

On the other hand, the serious income distribution problems in Mexico 
will either have to be addressed when the additional wealth is available, 
or will be worsened by the additional income from oil and gas. Either 
way, political instability may be a result. That instability would 
more than ever affect the United States if 5% of our natural gas supplies 
were hostage to it, in addition to our other ties. 

For these reasons, the United States' self-interest may not entire- 
ly coincide with a lower price for Mexican natural gas, if it results 
in a residue of bitter feeling of economic coercion and continued paternalism, 
and even if the domestic cost may be either substantially higher natural 
gas prices across the board, continued challenges to the fairness of regulated 
domestic natural gas prices, or both. On the other hand, failure to reduce 
the price by rolling in the expensive Mexican gas with cheaper American 
gas (from angry American producers), might render the gas uncompetitive 
and perhaps not salable, jeopardizing the entire project. A decision on 
the incremental pricing of such new sources will have much to do with the 
likelihood of early imports from Mexico. 

3.3.6.5. Conclusion . The proposal to import large quantities of natural 
gas from Mexico currently appears in limbo. It is not actively being pursued 
because of the entranched political position of the Mexican Government 
concerning its price on the one hand, and the reluctance of the U.S. Govern- 
ment to establish a new high price standard for U.S. gas supplies, with 
its ramifications on other imports and domestic politics, on the other hand. 
The trends appear to be moving toward the Mexican position, with gas price 



376 

rising rapidly and the current U.S. domestic supply surplus likely to 
evaporate. But the U.S. has strong bargaining power, as the only logical 
timely, and economic market for the gas. Untempered use of that bargaining 
power may cause problems in U.S. -Mexican relations, successful or unsuccess- 
ful, and if successful, may cause internal political problems in Mexico. 



377 

3.3.7. R atification of International Transportation Conventions* 
Issue Description 

\o oae aicernative for dealing with the issues of oil tanker safety 

and damage from tanker spills, it has been proposed that the United 

States adhere to a number of international conventions drawn up since 

1969. All require approval by the United States Senate. At issue 

is whether the provisions of these agreements are strong enough and 

whether more stringent provisions should be established through 

domestic legislation. 
3.3.7.1. Background 

ns of iiarch 1977, 18 conventions have been adopted under the 
sponsorship of the Inter-Governmental Maritime Consultive Organization, 
and they have entered into force upon ratification by maritime nations 
representing at least half of the world's merchant shipping tonnage. 
Eight of the 18 have been ratified by the United States. Of immediate 
concern to both the executive branch and Congress are three conventions, 
not yet ratified, that deal specifically with tanker safety and design 
standards and liability and compensation. They are: 

(1) International Convention for the Prevention of Pollution 
from Ships (1973). This treaty has not yet entered into force. 

It sets construction and equipment standards and operating procedures 
for tankers, including a considerable reduction in the amount of oil 
allowed in discharged ballast (in comparison with a 1954 treaty) and 
a requirement that new tankers of over 70,000 deadweight tons be 
constructed with segregated ballast capability. 

(2) International Convention on Civil Liability for Oil Pollu- 
, tion Damage (1969). Presently in force, it establishes limits of 

liability of approximately $160/gross ton or $16.8 million per 
incident, whichever is lesser, for any pollution caused by oil 
Prepared by Larry Niksch, Specialist in Asian Affairs 



378 

discharges. However, compensation would be provided only when damages 
occur within a ffetion's territory or territorial sea (out to three miles). 

(3) International Convention on the Establishment of an International 
Fund for Compensation for Oil Pollution Damage (1971). Presently not in force, 
it would create an international fund as an additional source of payment 
for oil pollution damages to the extent that protection afforded by 
the Liability Convention is inadequate. Limits for damages paid by 
the Fund may not exceed $36 million, except under special circumstances. 
The Ford Administration strongly advocated ratification of these treaties, 
but the Carter Administration had taken no position as of March 1977. 
On January 11, 1977, Secretary of Transportation William Coleman called 
on Congress to "implement international agreements imposing improved 
construction and operating standards as well as effective compensation 
regimes." Coletnan specifically urged Senate ratification for the Pollution 
Convention, the Civil Liability Convention, and the Compensation Fund 
Convention. He added that his Department was preparing implementing legislation 
on the Pollution Convention for future consideration by Congress. Coleman 
pointed out that the Civil Liability Convention was in force and therefore 
applicable to claims against U.S. ship owners. He argued that ratification 
would extend the convention's benefits to the United States claimants 
and that U.S. legislation could provide additional protection to American 
claimants. Moreover, for reasons of diplomacy, the State Department reportedly 
favors that the United States deal with these problems primarily through 
the international conventions. The American Petroleum Institute also has 
urged ratification. 

Also on January 11, Robert J. Blackwell , Assistant Secretary of Commerce 
for Maritime Affairs, presented the following arguments for a policy based 
on the international conventions: 



379 



Pollution of the ocean is an international problem which requires 
an international solution. 

Regulations of worldwide applicability offer the most practical 
promise for marine environmental improvement. 

Individual national regulations, no matter how strong, could 
produce a patchwork of requirements which could not be uniformly applied 
to merchant shipping. 

Application of uniform construction and operating standards will 
not adversely affect the U.S. merchant marine's competitive position. 

Unilateral regulations by the United States, it is further argued, 
would invite retaliation from other shipping nations, particularly the 
oil-exporting nations that have been building tanker fleets of their 
own in recent years, 

Despite these arguments, there is strong opposition in Congress 
to ratification of the three conventions. Opponents assert that 
agreements like the Pollution Convention and Fund Convention take years 
to secure worldwide approval, and even those that come into force are 
inadequately enforced. In practice they say, only strong unilateral action 
by the United States is likely to be effective. 

In September 1976, the House Merchant Marine and Fisheries 
Committee issued a report on a liability and compensation bill, which 
rejected implementing legislation for the Civil Liability and Fund 
Conventions. The report cited criticism that the Civil Liability 
Convention provided too strict a limitation on liability of seagoing 
ship owners. The Compensation Fund Convention was criticized because 
a major part of the fund would be derived from fees on oil imported 
into the United States — thus paid for by American consumer — but 
also because, in certain circumstances, a ship owner could receive a 
contribution from the fund of 25 percent of his liability. 



380 

Russell Train, Adminisiator of the Environmental Protection Agency, 
cited other weaknesses of the international conventions in his testimony 
of January 11. Train stated that the Pollution Convention "did not provide 
the stringent standards sought by the United States," including the proposal 
of double bottoms for vessels with a capacity of 20,000 deadweight tons 
or larger. Train also acknowledged that there is "substantial" U.S. industry 
opposition because the Convention covers inland waters; and he cited as 
an additional limitation the Convention's coverage of only new vessels 
but not existing tankers. 

With regard to the Civil Liability and Fund Conventions, Train 
pointed out that they apply only to damage to the territory or territorial 
sea and, as a result, would not have been available for compensation in 

the Argo Merchant mishap even if the United States had ratified them, 

3.3.7.2. Analysis 
in summary, fhere appears to be a general consensus that the United 

States should adopt unilateral measures to expand the territorial limits 

of tanker pollution regulation and require heavy liability responsibility 

for shipping companies responsible for accidents and damage. The basic 

disagreement appears to be whether ratification of the international conventions 

would hinder adoption and/or enforcement of U.S. regulations; whether 

enactment of unilateral legislation by Congress would help or hurt the 

chances of ratification of the conventions; and what effect unilateral 

legislation would have on U.S. relations with oil producing states and 

host countries for the tanker companies. 

The Ford Administration and Congress appeared to take different 

sides on these issues, but it remains to be seen what position the 

Carter Administration will adopt. On March 22, 1977, President Carter 

recommended ratification of the Pollution Convention, 



381 



References 



Becker, William, and Jim Mielke. Oil Spills and the Marine Environment. 

Issue Brief No. 77014. Washington, U.S. Congressional Research Service, 
1977 . 

Costello, Mary. Tanker Safety. Editorial Research Report. Vol. I, No. 9. 
Washington, Congressional Quarterly, Inc., 1977. 

Statement of William T. Coleman, Jr., Secretary of Transportation, before the 
Senate Committee on Commerce, Regarding Oil Tanker Accidents, January 
11, 1977. 

Statement of Honorable Russell E. Train, Administrator, Environmental Protection 
Agency, before the Senate Committee on Commerce, January 11, 1977, 

U.S. Congress. House of Representatives. Oil Pollution Liability. Report. 

Washington, U.S. Govt. Print. Off., 1976. (94th Cong., a 2d sess. House. 
Report no. 94-1489, Part I.) 



382 



3.3.8. Liquefied Natural Gas: Hazards, Safety Requirements, and Policy Issues 

Importation of liquefied natural gas (LNG) into the lower 48 States 
from Alaska or foreign sources is expected to increase. This fuel would 
supplement the Nation's declining reserves of natural gas. However, 
LNG poses significant safety risks which may require review of existing 
procedures and regulations for its shipment, handling, and storage. 
New guidelines for the siting of LNG storage terminals, legislation 
to reassign and coordinate Federal responsibilities over LNG systems, 
and the reappraisal of national policies affecting the supply of and 
demand for LNG may be necessary before a large number of plants are 
constructed . 

3.3.8.1. Introduction . In recent years. Congress has repeatedly 
directed attention to the adequacy of the Nation's long-term gas supply. 
Experts have noted that prospects for meeting demands for natural gas 
through 1985 appear to be worsening. For example, only experimental 
quantities of synthetic natural gas ( SNG) from oil shale or coal are 
likely to be produced before 1985. Only small quantities of SNG can 
be produced from petroleum feedstocks. The outlook for obtaining increasingly 
large quantities of gas from the Outer Continental Shelf is uncertain. 

Accordingly, attention is focusing on the use of liquefied natural 
gas (LNG) as a means to supplement conventional gas supplies. The huge 
gas reserves located in about 20 foreign countries and Alaska can be 
transported in specially-designed tankers to the conterminous 48 States 
if it is cooled and liquefied; a process that compacts natural gas to 

*/ Prepared by Paul Rothberg, Analyst, Science Policy Research Division. 



383 

1/600 of its volume. LNG can be stored in large quantities until 

it is needed and can be transported to places that cannot be reached 

by pipelines. Many gas companies store surplus gas during seasons of low 

use as LNG and regasify the liquid to meet demands when necessary. Thus, 

LNG systems are versatile and can help meet gas demands by supplying fuel 

when it is needed. 

3.3.8.2. Existing and Expected LNG Receiving Facilities. The technology 
for importing, receiving, storing, and regasifying LNG is a proven technology, 
A considerable international trade in LNG already exists: Japan imports 

about 80 percent of its gas in liquid form, Western Europe 5 percent, and 

1/ 

the United States somewhat less than .1 percent. 

The quantity of LNG imported into the lower 48 States is expected 
to increase significantly over the next 10 to 15 years. It is not pos- 
sible to determine accurately the exact quantity of LNG that will be 
imported. New projects are continually being planned; announced projects 
are frequently cancelled; contracts are continually terminated 
and renewed. "Given these uncertainties, it is virtually impossible 

to know, with a high degree of reliability, how much and where LNG will 

2/ 

be used in the U.S. during the 1980-1990 time frame. 



IJ Drake, Elisabeth and Robert C. Reid. The Importation of Liquefied 
Natural Gas. Scientific American, v. 236, April 1977:22. 

ll Fink, R.J., B.A. Bancroft, and T.M. Palmieri , The Strategic Petroleum 
Reserve and Liquefied Natural Gas Supplies: Final Report. TRW Energy 
Systems Planning Division, Virginia, 1977:35. 



384 

Even though plans for LNG facilities are frequently changing, 
useful information can be obtained by reviewing current activities 
of the LNG industry. In the United States, there is one LNG receiving 
facility in operation; two nearing completion; and up to six proposed. 

Distrigas Corporation was the first U.S. company to import large 
quantities of LNG. Their effort began in 1971, with a project to bring 
15 billion cubic feet of gas per year from Algeria to Everett, Mass. 
In 1976, Distrigas received only 11 cargos of LNG which totalled 10.8 
trillion Btus. In April 1976, this Corporation signed a new agreement 
to import approximately 115 million cubic feet of gas daily for 20 years 
beginning in 1978. 

Another LNG facility, which cost over $100 million, was completed 

in 1974, at Staten Island, New York. Because of its location near heavily 

populated areas and other safety, regulatory, and environmental concerns, 

this plant has not yet received all of its required operating permits 

and importation of gas may not be forthcoming for some years, if ever. 

This plant, now owned by Public Service Electric and Gas Company of New 

5/ 

Jersey, is now "mothballed" , and has no supply or shipping contracts. 

A fleet of nine newly-built LNG ships, owned by El Paso Natural 
Gas Company, is soon expected to begin transporting LNG from Algeria 
to Cove Point 5 Maryland, and to Elba Island, Georgia. These ships 

3/ Daniel, E.J. and P.J. Anderson. International LNG Prospects 

Continue Progress as New Plans Evolve. Pipeline and Gas Journal, 
June, 1977:30. 

4/ Personal communication with Richard Norman, of Energy Storage Ventures, 
1977 . 

_5/ Personal communication with Ben Bakerjian of Public Service Electric 
and Gas Co. of New Jersey, 1977. 



385 

are capable of delivering a combined average of one billion cubic feet per 
day to the two facilities. Another U.S. terminal is expected to be 
built near Lake Charles in Calcasieu Parish, Louisiana. This terminal 
may receive about 168 billion cubic feet of LNG annually from Algeria for 
20 years, starting around 1980, assuming the plant proceeds as scheduled. 

The long-term need for natural gas may give rise to additional terminals 
on the North Atlantic, Gulf and West coasts for receiving LNG from Algeria, 
Nigeria, Trinidad, .Indonesia, Libya, Iran, U.S.S.R., or Alaska. 

Plans for these terminals are detailed in Table I. 

The demand for LNG, as well as the availability of this fuel from 
abroad, is likely to increase. The Congressional Research Service has 
projected the following amounts of LNG imports: .5 trillion cubic feet 
(tcf) in 1980, 1.2. tcf in 1985, and 1.7 tcf in 1990. Assuming these 
figures prove correct, LNG would contribute 2.6%, 6.1%, and 8.1% of total 
gas supply in 1980, 1985, and 1990, respectively. (CRS's projection 
assumed that no major institutional barrier would interfere with the 
siting of LNG terminals in the coastal zone). 

The likelihood of large scale LNG imports depends not only on the 
Federal import policy adopted and its considerations of source and 
dependability, but also on the economics of using LNG. Substantial 
quantities of LNG imports are unlikely at prices competitive with the 
current prices of domestic natural gas, because of the combination of 
high costs of transportation and processing, combined with the desire 

6^/ U.S. Congress. House and Senate. Committees on Energy and Natural 
Resources, Commerce, Science and Transportation, and Interstate and 
Foreign Commerce. Project Interdependence: U.S. and World Energy 
Outlook Through 1990. By the Congressional Research Service, Library 
of Congress, (Washington, D.C., U.S. Govt. Print. Office, June 1977) 
p. 29. 

24-786 O - 76 - 26 



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O ^ 
t^i O 



o 

<M o 



a X 



(J u ~ 1. 



H 3 u; i. 



387 

of exporting nations for an FOB (free on board) price comparable to 
the energy equivalent price received for oil exports. While this 
situation may change in the future as natural gas supplies continue 
to diminish, at present imported LNG must be "rolled-in" (averaged) 
with pipeline gas so that the average price for delivered gas is 
competitive . 

Current Federal policy appears to allow such averaging of costs 
instead of requiring LNG be sold incrementally at its own cost. The 
Federal Power Commission in Opinion 796-A, issued June 30, 1977, reversed 
its own earlier ruling that LNG imports by the Trunkline Gas Company 
be priced separately to the user when FPC determined that such a require- 
ment would render the Trunkline project unf inanceable , effectively preventing 
it from being attempted. The FPC concluded that the need for the ad- 
ditional natural gas promised by the project outweighed its inability 
to stand on its own economically under current conditions, and that it 
should not be delayed until future conditions made it economic. The 
FPC opinion suggested that other alternate sources for gaseous fuel — 
deregulated natural gas, coal gasification, production of methane 
from geopressured zones, imports of liquefied petroleum gas (LPG), or 
manufactured (SNG) from petroleum liquids — are not certain to be less 
expensive than LNG over the middle and long term. Therefore the FPC argued 
that LNG import projects, for which the technology is already available, 
should not be discouraged, because of the probable need for supplemental 
gas from some source in the future. 



388 

Besides considering how much LNG will be imported into the United 
States, it is important to examine the distribution and potential impact 
of LNG on regional natural gas supplies. Table II, prepared by the Energy 
Systems Planning Division of TRW, presents a forecast of expected State 
and regional dependencies on LNG. This data was based on projects previously 
filed with the Federal Power Commission, and was calculated by dividing 
estimated import levels by projected and prorated values for total con- 
sumption of gas for each State. According to TRW, the Northeast will 
have the largest dependence on LNG. New Jersey is expected to have the 

largest dependency of 47 percent of total gas use, followed by Vermont 

7/ 

at 42.5 percent, and Connecticut and Arizona at 30.9 percent. Even though 
these exact percentages may change, the contribution of LNG to the gas 
supplies of the eastern United States and States like Ohio, Mississippi, 
Louisiana, Arizona, and California, may be significant if planned LNG 
terminals are completed. 

Dependence on natural gas as a fuel has been established in virtually 
every part of the United States, and supplies of natural gas have been 
allocated during the growing shortage to those uses considered to be the 
highest priority. LNG imports may be imported in New England and other 
parts of the country far from the Texas-Louisiana center of natural gas 
production, because in these regions the high pipeline transportation cost 
component for natural gas makes LNG seem relatively economic. But if 
imported LNG is used in these regions, it will primarily supply residential 



y Fink, F.J. et al., op. cit., p. 51 



389 



TABLE II: State and GRC Regional LNG Dependencies: Projected LNG Percentage 
of 1985 Projected Consumption for Projects Filed with the FPC. */ 



Region 
NEW ENGLAND 



Connecticut 
New Hanpshire 
Vermont 



APPALACHIAN 



Kentucky 
Maryland 
New Jersey 
New York 
Ohio 

Pennsylvania 
Virginia 
West Virginia 



SOUTHEAST 

Alabama 
Florida 
Georgia 

South Carolina 
Tennessee 

GREAT LAKES 

Illinois 

Indiana 

Michigan 

MID CONTINENT 

Missouri 

GULF COAST 

Louisiana 

Mississippi 

Texas 

PACIFIC SOUTHWEST 

Arizona 
Cali fornia 
Nevada 



LNG % of Area's 
Total Gas Consumption 

28.1 

30.9 
28.9 
42. 5 

12.1 

3.6 
12.2 
47 .0 

9.5 
11.7 

5.5 

8.9 

4.5 

14.6 

20.8 

6.2 
23.6 
25.0 

2.2 

4.5 

1.8 
19.0 
1.7 

.7 

2.9 

3.1 

9.4 
20.6 
.7 

19.4 

30.9 
20.9 
7.2 



Source: R.J. Fink et al. of TRW, Inc. The Strategic Petroleum Reserve and 
Liquefied Natural Gas Supplies. 1977. p. 52. 



390 

and other high priority customers, building a perhaps dangerous reliance 
among critical needs, and lessening the utilization of the pipelines which 
brings natural gas from the Gulf region. If, on the other hand, LNG is 
brought primarily into the traditional natural gas producing areas along 
the Gulf Coast, it may be more difficult for it to compete with the 
other fuels among the lower priority users who would be seeking energy. 
Should natural gas supplies continue to decline to the point that imported 
LNG would be needed for continuous supplies to high-priority customers in 
regions distant from the producing area, its delivered cost would be in- 
creased by the pipeline costs. But at least dependency on imported sup- 
plies of natural gas could be equalized in differing regions. 

The institutional changes that might be required by LNG policies should be 
noted. If those companies which build LNG terminals and receive shipments 
use the imported LNG exclusively, their service areas might become 
less vulnerable to domestic natural gas shortages, but more dependent on 
overseas energy sources and more vulnerable to a cutoff. However, any 
attempt to spread the risk or benefits of imports of LNG by allocating 
the gas among all or many pipelines or distributors would be contrary 
to the current structure of the natural gas industry, which makes each 
company primarily responsible for its supplies. If other companies 
may sometimes have to use LNG imports for peak needs, it may be appropriate 
to require them to make early contributions toward construction and 
operation of terminals. 

Any sizeable increase of LNG imports would raise several questions 
including the following: 

(1) Should the United States establish an LNG import policy? 



391 

(2) What physical or safety risks are involved in transporting LNG? 

(3) Where and how should LNG facilities be sited? 

(4) How efficient and effective is the Federal Government's reg- 
ulation of LNG systems? 

These issues and others are discussed in the following sections: 

3.3.8.3. LNG Importation Policy . During the Ford Administration, 

the Energy Resource Council proposed guidelines to limit imports' of 

LNG to 2 trillion cubic feet per year. Of that amount, no more than 

1 trillion cubic feet could be imported from any one country. The Carter 

Administration has recommended in its National Energy Plan a more flexible 

8/ 

policy that sets no upper limit on the quantity of LNG imports. Under 
the new policy, each application to import LNG would be reviewed with 
consideration for such factors as its availability at a reasonable price 
without undue risks of dependence on foreign supplies, the reliability 
of the selling country, the safety conditions associated with the importing 
terminal, and the total costs of the operation. 

Several Federal policies and programs influence the contribution 
of LNG to the U.S. energy supply. For example, the quantity of LNG 
imported into the 48 States depends partly on Federal policy affecting 
LNG import levels and the capability of the Federal Government to supply 
loans, guarantees, or other forms of financial assistance if needed by 
LNG operators. In addition, the ability of the United States to compete 
with other countries for LNG supplies, the relative prices of energy 
fuels, and the willingness of foreign countries to enter the LNG market 

^/ Executive Office of the President. The National Energy Plan. (Washington, 
D.C.: U.S. Government Printing Office, 1977), p. 57. 



392 



may have a considerable effect. The ability of gas companies to obtain 
the 140 or more Federal, State and local permits and regulatory ap- 
provals for a terminal also influences the rate of development of 
the domestic LNG industry. 

There seems to be little coordination of the various Federal policies 

that affect the importation of LNG. Federal officials have indicated that 

9/ 

the U.S. Government does not have a consistent policy on LNG imports. 

According to the Federal Energy Administration (FEA), the lack of such 

a policy has contributed to the planning problems of private industry, 

and has compounded the uncertainty which faces suppliers, consumers, 

and State regulatory groups as they attempt to deal with the natural 

gas situation. In addition, the lack of such a policy has enabled Algeria 

a member of the Organization of Arab Petroleum Exporting Countries, 

"to emerge as the major prospective foreign supplier of LNG to the U.S., 

10/ 

and as the potentially-dominant world supplier of LNG. " 
According to the FEA, 

The problem at hand is the definition of a comprehensive 
and consistent U.S. Government policy towards the importa- 
tion of liquefied natural gas (LNG). This policy should be 
comprehensive enough to condition the operating practices of 
government agencies which have a major impact on the develop- 
ment of LNG import ventures; the principal relevant agencies 
at the Federal level are the Export-Import Bank, the Maritime 
Administration and the Federal Power Commission. 11/ 



£/ Office of Policy and Analysis (of the Federal Energy Administration). 
Outlook for U.S. Imports of Liquefied Natural Gas (LNG). Draft Report 
Oct. 7, 1975, p. 1. 

10/ Ibid. , p. 1. 

11/ Ibid. , p. 1. 



393 

If the Congress chooses, as part of comprehensive legislation re- 
garding LNG, it could influence or formulate an LNG importation policy. 
In developing such a policy, congressional review might consider the 
relative advantages and disadvantages of: 

— setting a limit on LNG import levels; 

— directing the distribution of LNG throughout the States now 
serviced by pipeline systems; 

— limiting the quantity of LNG that could be imported from any one 
country; and 

— relying on free market dynamics to determine LNG supply and demand. 
In addition, congressional attention might be directed at ways in 

which Federal policy could be designed to help assure a "secure" supply 

of LNG at reasonable prices for the American consumer; Federal policy 

could foster the U.S. position in the international LNG market; and 

how Federal policy could reduce U.S. vulnerability to a potential LNG embargo. 

3.3.8.4 Hazards and Safety Concerns . If decisions are made to 
increase the quantity of liquified natural gas imported into the lower 
48 States, effective measures will be needed to ensure against the unique 
dangers it poses. These dangers include flameless explosions, enormous 
fires, radiant heat, flame inhalation, asphyxiation, frostbite, and 
uncontrolled vapor clouds. Unexpected release of LNG resulting from 
a collision of an LNG tanker, from faulty containerization of LNG on 
board, or from careless handling or improper storage or processing 
of the material on land could endanger life and property over a large 
geographical area. 

The safety record of the LNG industry over the last 30 years has been 
good. Over 2,000 shipments of LNG have been made without incident. The more 



394 

than 60 LNG peak shaving plants now operating in the United States and Canad; 
have had an excellent safety record. The industry's history, however, 
is not perfect. In 1944, a small LNG storage tank failed in Cleveland, 
Ohio, and a disastrous accident resulted in part because of lack of dikes 
and improper materials. Over 130 people died from the explosions and 
fires that resulted. 

Debate over the risks of handling, transporting, and storing LNG is 
expected to continue, especially since expert opinion varies as to the 
most effective approach for prevention and remedy. Still to be faced is 
the major question of whether Federal, State, and local safety, construction 
and siting regulations are adequate to allow the large scale importation 
of LNG to proceed, with acceptable risks to the public. 

Although several congressional committees have examined the hazards 
and safety requirements of LNG systems, it appears that the increased 
use of this fuel may require new measures to further reduce possible loss 
of life and property. 

Several options seem to be available to the Congress to accomplish 
this purpose, including: 

(1) Further investigation of the adequacy of LNG safety regulations 
and their means of enforcement and, if necessary, enactment of legislation 
to re-design safety standards and to implement other appropriate measures. 

(2) Review and expansion of Federal and industry research on LNG 
chemistry, transportation, and safety. Little is known about the phenomena 
that would result from a catastrophe involving LNG. Dr. Edward Teller 
recently stated that current understanding of the potential hazards from 
LNG accident is roughly comparable to our understanding of the hazards of 



395 

nuclear reactors 25 years ago. Research may provide more information on 

the properties and behavior of LNG, thus helping to assure that design, 

construction, and operation of vessels and facilities are reliable and 

adequate. In addition, research into the results of collisions by LNG 

tankers and the implementation of appropriate countermeasures may reduce 

the hazards of LNG accidents. As stated by Drake et al., it can 

be expected that further experience in handling liquefied natural gas and 

further research by the industry and by regulatory agencies will raise 

12/ 

the level of safety in its use even higher. 

(3) Review of the technical and financial capabilities of com- 
munities and private industry to contain LNG fires and, if necessary, 
enactment of legislation to enhance these resources. Hearings were 
held in the 94th Congress on H.R. 11439, a bill to establish a national 
marine firefighting program. This legislation, if passed, could have 
upgraded the capability of regional units to contain LNG fires. 

(4) Investigate the technical feasibility and the legal considera- 
tions of constructing an offshore LNG facility designed to significantly 
reduce the risks to populated areas onshore. 

3.3.8.5. Siting of LNG Facilities Onshore . Deliberation among environ- 
mentalists, concerned citizens, and energy companies over the siting 
of LNG receiving and storage facilities have produced emotional controversy. 
Difficulty arises because sites located in either rural, industrial, 
or residential areas usually offer tradeoffs between environmental impact 



12/ Drake et al., op. cit., p. 29. 



396 

impact and safety. A site selected in a rural area raises concerns 
about the impact on the natural environment, even though a minimum number 
of people and amount of property might be endangered in the event of 
an accident. Industrial locations tend to have a minimum impact on 
the environment, but present a greater risk to human safety and industrial 
property. Siting of a storage or receiving plant near a heavily populated 
area could constitute a major safety hazard for millions of people and 
could result in enormous property damage in the event of a major LNG 
acciddent. Wherever these plants are sited, they must be designed and 
operated to prevent accidental and harmful releases of LNG. 

Site selection is initially undertaken solely by the industry group 
proposing an LNG import facility. Federal and State Governments and other 
groups react to industry's proposal primarily through the Federal reg- 
ulatory process. This regulatory system governing LNG import facilities 
is relatively complex, and generally requires several years of hearings 
and reviews before a company obtains all of the necessary Federal permits 
and approvals. Federal agencies that may exert a major influence on the 
siting of LNG facilities include: Department of Energy, Office of Pipe- 
line Safety Operations, and the U.S. Coast Guard. Increasingly, State 
governments are demanding more of a role in the siting of LNG import 
facilities . 

At present there is no Federal siting policy to govern the location 
and size of LNG plants throughout the United States. As a result, LNG 
facilities might be constructed in some coastal regions and not in others. 
It is also possible that LNG receiving terminals might be scattered along th 
coasts without long-range planning or proper management of the coastal zone. 



397 

Thus, there is reason to consider whether a Federal siting policy 
should be established; and if so, on what criteria should this policy 
be based. If a national siting policy were developed, it seems logical 
that its institution should precede the construction of a large number 
of LNG receiving terminals. Last year, Pennsylvania, New York, New Jersey, 
and Delaware petitioned the Federal Power Commission to promulgate 
national safety standards that would keep LNG port facilities out of 
populous areas. According to a New York Times articles of October 7, 
1976, States officials suggested that the LNG terminals "be confined to 
areas of low population density, with suitable buffer zone maintained 
around them." 

Recently, congressional attention has focused on these concerns. 
In the 95th Congress, Congresseman John Dingell and other Members sponsored 
H.R. 6844, a bill to regulate the siting, design, construction, and operation 
of facilities to be used for the transportation, storage, and conversion 
of LNG. (President Carter's National Energy Plan suggested that strict 
siting criteria should foreclose the construction of new LNG terminals 
in densely populated areas. Congressman Edward Beard has introduced legislation 
(H.R. 9773) that would require the Federal Power Commission to withhold 
any license for LNG construction or expansion without the approval of 
the State or States involved. Senator Claiborne Pell has introduced legislation 
(S.2273) to confer on the Secretary of Energy jurisdiction over construction 
permits and operating licenses for liquefied natural gas facilities, and 
to provide the Govjernor or appropriate State officials with a major input 
into, and possible veto over. Federal siting decisions. 



398 

Local communities, State governments, and private industry may op- 
pose a Federal policy which dictates the standards for siting of LNG 
terminals; instead, they may want to rely on the existing regulatory 
framework. Regardless of which option is selected, safety, environmental, 
and physical conditions are to be considered in any siting decision. 

3.3.8.6. Siting of LNG Terminals Offshore . The concept of LNG 
terminals offshore is beginning to receive increased attention by Federal, 
State, and industry officials. The potential safety hazards to onshore 
areas from LNG operations may be lessened by moving part or all of the 
LNG receiving terminal and its associated storage tanks and regasification 
units many miles offshore. In the event of a spill or other mishaps, 
those miles of ocean might constitute an effective buffer, giving a 
combustible or explosive gas cloud more opportunity to disperse before 
reaching any populated areas. Environmental damage of a spill many miles 
from shore may be minor because of the quick evaporation of LNG. 

In a study by the Stratos Division of Fairchild Industries, five 
different types of offshore LNG receiving terminals were considered as 
candidates for siting off the California Coast. These were: natural 
island facility, artificial island, floating facility, fixed and mobile 
structure, and subsea facility. Fairchild Industries concluded that each 
of these terminals was technically feasible. Even though Fairchild 
Industries judged specific sites to be environmentally acceptable, they 
concluded: "sufficient regulatory authority does not presently exist 



399 

to enable granting all of the approvals necessary for siting, constructing, 

13/ 

and operating any offshore receiving terminal." 
Their report stated: 

(1) No Federal legislation has been found enabling the granting 
of approvals for siting and associated leasing of an LNG ter- 
minal on the Outer Continental Shelf (OCS) 

(2) No Federal legislation has been found enabling the granting of 
a gas transmission pipeline right-of-way and lease across the 
OCS for transport of gas other than that produced from sub- 
merged lands in the immediate vicinity of the pipeline; 14 / 

Henry Marcus and John Larson of MIT have arrived at similar conclusions. 

They maintain "there is no Federal agency with the power to authorize 

the siting, construction, and operation of an offshore LNG terminal out- 

15/ 

side the U.S. territorial seas. They also noted that the Department 

of the Interior does not have the authority to grant rights of way and 

associated leases for the laying of pipelines for an offshore LNG marine 

16/ 

terminal in the OCS. 

The Congress may choose to address the regulatory and siting questions 
associated with the construction of an offshore LNG facility outside the 
U.S. territorial sea. According to Fairchild's report and the MIT study, 
it appears that congressional legislation is required before an offshore 
terminal is built on the OCS. Until this siting question is resolved, 
it is unlikely that industry would proceed with construction of an off- 
shore LNG facilities on the OCS. 



1^ Fairchild: Stratos Division. Offshore LNG Receiving Terminal 
Project. Volume I - Management Summary, March 31, 1977: 51. 

14/ Ibid. , p. 51. 

15 / Marcus, Henry S. and John H. Larson. Draft Final Report: Offshore 
Liquefied Natural Gas Terminals. June 1977. pp. 8-30. 



16/ Ibid., p. 8-30. 



400 

3.3.8.7. Federal Responsibilities and Regulations . Many Federal 
agencies regulate and influence the safety, siting, and economics of 
LNG receiving, storage, regasi f ication , and shipping operations. 
The Department of Energy, U.S. Coast Guard, Army Corps of Engineers, 
Maritime Administration, Office of Pipeline Safety, Department of the 
Interior, and the Environmental Protection Agency have responsibilities 
over various aspects of LNG importing systems. State and local governments 
also affect LNG facilities. 

The regulatory system governing LNG imports and facilities, is, 
by necessity, rather elaborate. Decision making related to the safety 
of planned facilities, siting of LNG terminals, and the priority of 
imported gas is detailed and requires extensive proceedings. 

According to many industry spokesmen, the existing regulatory system 

12/ 

for LNG systems is extremely complex and cumbersome. Numerous 

Federal, State and local permits and regulatory approvals are required 

for an LNG receiving terminal and its associated facilities. Delays in 

obtaining approvals from Federal, State, and local agencies have slowed 

18/ 

many projects and have caused cancellation of others. In addition, 

delays in obtaining regulatory permits are a contributing factor to 
escalated costs for LNG facilities. Some of these increased costs 
are eventually passed on to the consumer. Delays in obtaining regulatory 



17 / Based on personal discussions with various industry spokesmen, 1977 
18/ Marcus, Henry S. and John H. Larson, op. cit., pp. 1-6. 



401 

decisions may also result in a weakening of the U.S. competitive position 

in the international LNG market. Potential suppliers of LNG may sell 

their product to countries whose policies facilitate the importation 

of LNG. For example, Indonesia may sell some of its supplies to Japan 

rather than to the United States, because U.S. regulatory delays have 

19/ 

reportedly resulted in unconsummated contracts. 

Congressional attention has focused on jurisdictional gaps, over- 
laps, and disputes between Federal agencies. For example, hearings 
were held in 1973 before the Special Subcommittee on Investigations of 
the House Commerce Committee to review Federal justisdictional responsib- 
ilities with respect to LNG storage facilities. The Subcommittee's 
report found that overlapping regulations of LNG storage safety had led 

to duplication of effort, fragmentation of responsibility, and inefficient 
20/ 

administration. Some operators of LNG facilities maintain that they 
can adjust to one set of regulations, but two or more sets present major 
di f f iculties . 

A regulatory system that allows reasonable plans to proceed with 

21/ 

some degree of certainty is very important to the LNG industry. Several 
options are available to reduce or eliminate interagency conflicts and 
jurisdictional problems. Mandated cooperative efforts between agencies 

19 / Personal communication with David Ray of the American Gas Association, 
1977. 

20 / U.S. Congress. House, Committee on Interstate and Foreign Commerce. 

Special Subcommittee on Investigations. Legislative Issues Relating 
to the Safety of Liquefied Natural Gas Storage, 93rd Congress, 2nd 
Session, (Washington, D.C.: U.S. Gov. Print. Office, March 1974). 

21 / Based on conversations with several industry spokesmen. 



24-786 O - 78 - 27 



402 

is one option. Alternatively, the Congress could follow the suggestion 
of John Nassikas (former chairman of the Federal Power Commission) to 
enact legislation that would delegate or clarify responsibilities of 
the respective Federal agencies involved. Another course of action 
would be to designate one Federal organization, such as the Department of 
Energy or the Department of Transportation, as having primary responsibili 
for regulating LNG systems. Regardless of which option is chosen, it 
appears beneficial to resolve jurisdictional problems prior to ship- 
ment of substantially increased quantities of LNG into the lower 48 
States. 

In addition to its regulatory responsibilities, the Federal Govern- 
ment helps finance major LNG tanker construction projects. About 18 LNG 
carriers are being built, of which 11 are under Federal construction 
subsidy contracts. One of the largest Federal loan guarantees ever offered 
was recently awarded to underwrite construction of 7 LNG ships to be 
built by General Dynamics in Quincy, Mass. The first of these ships, 
LNG-41, is now completed. 

3.3.8.8. Summary . In view of the projected U.S. gas supply situation 
increased quantities of LNG are likely to be imported into the lower 
48 States. Because of questions of energy policy and the inherent dangers 
of transporting, storing, and regasifying this fuel. Congress may choose 
to become increasingly involved in the formulation of policies af- 
fecting the importation and regulation of LNG. 

This chapter has identified three areas of concern that appear 
to warrant additional attention: 



403 



(1) Federal policy on the importation of LNG, including questions 
of dependency, pricing, and distribution; 

(2) Siting of LNG import terminals; and 

(3) Safety and regulatory responsibility of various Federal agencies. 
Since these issues are closely interrelated, they may need to be 

considered together, and within the context of other energy and environ- 
mental policies. 



References 

Alaskan Natural Gas Transportation Systems economic and risk analysis; 
final conclusions and results. Prepared by the Aerospace Corpora- 
tion for the Department of the Interior, February 1976. (NTIS, 
PB-250-361) 

Carl, Robert. Liquefied natural gas carriers and their development. 

U.S. Naval Institute proceedings, v. 103. [Washington] April 1977. 
p. 99-101. 

Corrigan, Richard. Energy Report/El Paso: Arctic firms compete for 
Alaska gas transport rights. National journal reports, v. 6, 
August 3, 1974: 1155-1159. 

Drake, Elizabeth, and Robert Reid. The importation of liquefied natural 
gas. Scientific American, April 1, 1977: 22-29. 

Fairchild, Stratos Division. Offshore LNG receiving terminal project. 
V. 1 -- management summary, March 31, 1977, 51 p. 

LNG report. Pipeline and gas journal, June 1974, v. 201, no. 7. 

LNG report. Pipeline and gas journal, June 1976, v. 203, no. 7. 

Marcus, Henry S. and Larson, John H. Offshore liquefied natural 

gas terminals. Draft. Final report. Cambridge, Massachusetts 
Institute of Technology, June 1977. p. 8-30. 

Office of Technology Assessment. Transportation of Liquefied Natural 
Gas, September 1977. 

Omang , Joanne. Cove Point LNG facilities: an industry being born. 
Washington Post, Nov. 14, 1977. 



404 



Prudhoe gas reserves are center of pipeline battle. Oil and gas 

journal, v. 72, November 25, 1974: 96, 100, 102, 104, 106, 108, 
112, 114. 

Purvin and Gurtz, Inc. Analysis of the proposed LNG transportation 
system for northern Alaskan natural gas. Washington, D.C., 
April 1975, 70 p. 

U.S. Congress. House. Committee on Interior and Insular Affairs. 

Subcommittee on Public Lands. Alaska Natural Gas Transportation 
System. Hearings, 94th Congress, 1st session. Oct. 9, 1975. 
Washington, U.S. Govt. Print. Off., 1975. 340 p. 
"Serial no. 94-36" 

U.S. Congress. House. Committee on Interstate and Foreign Commerce. 

Special Subcommittee on Investigations. Staten Island explosion: 
safety issues concerning LNG storage facilities. Hearings. July 10, 
11, and 12, 1973. 93rd Cong., 1st sess., 1973, 795 p. 

. House. Committee on Interstate and Foreign Commerce. 

Special Subcommittee on Investigations. Legislative issues relating 
to the safety of liquefied natural gas storage. 93rd Cong., 2d sess. 
March 1974, 24 p. (Subcommittee print.) 

. House. Committee on Interstate and Foreign Commerce. 

Subcommittee on Energy and Power. Hearings. Alaskan natural gas 
transportation. May 17, 18, and 19, and August 6, 1976. 94th Cong. 
2d sess. , 1976 , 719 p. 

U.S. Federal Energy Regulatory Commission. Initial decision upon 
applications to import LNG from Algeria. (El Paso Eastern 
Company, et al.), Docket Nos. CP77-330, Washington, October 1977. 
134 p. 

. Initial decision on importation and sales of Algerian li- 
quefied natural gas. (Tenneco Atlantic Pipeline Co., et al.) 
Docket Nos. CP77-100, Washington, November 1977. 

U.S. General Accounting Office. Natural gas shortage: the role of 

imported liquefied natural gas. Washington, D.C. October 1975, 
45 p. 



405 

3.3.9. LPG Import Levels, Safety, and Sources */ 

LPG (Liquified Petroleum Gases), consisting primarily of propanes 
and butanes, are a significant source of fuel in the United States, sup- 
plying 2.0660 quadrillion Btu's in 1976, or about 3% of total U.S. energy 
demand. Capable of substituting directly for natural gas, which is in 
short supply, or providing feedstock for SNG manufacture, LPG is also 
capable of being shipped from overseas at much less expense than natural gas, 
which must be liquified and carried with elaborate equipment and pre- 
cautions. New international sources of LPG are beginning to come on 
stream, making quantities of this clean-burning fuel available that were 
formerly wasted. Because of its usefulness, subst itutabi lity for natural 
gas, increasing international availability, and importability , it is 
possible that imports of LPG will increase markedly over the next few 
years. This poses questions of the extent of the likely traffic, the 
safety of such shipments of a highly volatile fuel, and the dependence 
that might be built up upon overseas suppliers. 

3.3.9.1. Background . Liquified petroleum gases are produced from 
oil and gas wells like natural gas, and are also produced from refineries 
like petroleum products. They are transported like petroleum liquids, but used 
like natural gas. Natural gas liquids are "stripped" from the gas stream 
in producing fields by processing plants, and made up about 70% of the 
LPG produced in the U.S. in 1976. Liquified Refineries Gases (LRG) made 
up the other part of U.S. production, but chemically the products are 
identical. The three main constituents of LPG are propane, butane, 
and isobutane, but there are quantities of other materials produced 

V Prepared by John W. Jimison, Analyst, Environment and Natural Re- 
sources Policy Division. 



406 

at the same time, such as ethane, which are used primarily for petro- 
chemical feedstocks rather than for fuel. Propane is the lightest of the 
three, has the lowest vaporization point, and is the most abundant. 

A separate market for LPG has grown in the United States during the last 
65 years, utilizing "bottled gas" for multiple purposes in the residential, 
commercial, and industrial sectors, particularly in areas where natural gas 
pipelines and distribution lines have not brought the cheaper fuel. This 
traditional market has been softened in recent years by the first rise 
of LPG prices above fuel oil levels in 1973, a reversal of previous re- 
lationships. With the beginning of the natural gas shortage in the early 
1970' s, however, the substitutability of LPG for natural gas began to put 
new pressures on an LPG market already burdened by the decline in production 
of natural gas (and consequently of the natural gas liquid that are found 
with the gas). In 1973, it was deemed necessary for the Federal Government 
to allocate domestic production of propane and to control its prices, in 
order to protect traditional users from being outbid by natural gas users 
seeking fuel to offset increasing curtailments, even though many of the 
traditional users could convert to other fuels. Waterborne imports can 
be sold to industrial customers who do not have base-period allocations. 

LPG is liquified under moderate pressure. At 60 degrees Fahrenheit, 
Butane requires pressurization of about 40 pounds per square inch or more 
to be liquified; propane, about 110 pounds per square inch or more. Butane 
liquifies under atmospheric pressure at 32 degrees Fahrenheit, and propane 
at -44 degrees. By contrast, natural gas will not liquify at atmospheric 
pressure above -259 degrees. These properties make LPG relatively easy to 
move via truck, rail car, barge, or ship, as well as by pipeline, the only 
widely used method of transporting natural gas. 



407 

3.3.9.2. Domestic Market for LPG. Potential demand for LPG, including the 

recent demand for synthetic natural gas and propane/air mixtures for standby 

uses or peaking use by natural gas utilities, exceeds domestic supply. 

There are some imports of LPG despite the fact that world market prices 

for delivered LPG, currently running about $.33 per gallon for propane, 

exceed current domestic prices by about $.04 per gallon, and some producers' 

prices for domestic propane are as low as $.23. Light fuel oil, the main 

competitor for industrial purposes to propane, is imported at about 36c 

per gallon, which is equal to propane at 24c per gallon. Price controlled 

natural gas is cheaper yet, averaging about $.75 per Mcf at the wellhead, 

the equivalent of propane at $.07 per gallon. New natural gas in interstate 

commerce may sell for twice that much, and three times that much in 

unregulated intrastate commerce, but in all cases less expensive than propane. 

Natural gas supplies are falling, however, and domestic propane pro- 

t 

duction has paralleled that decline, except from refineries which have 
maintained production by increased imports of crude oil. If crude oil 
imports are restricted or reduced, however, this source of LPG will also 
be limited. Hence there is considerable interest in LPG imports, even at 
prices somewhat above the natural gas equivalent. This price gap is narrowing, 
moreover, because of the rapid rise of natural gas prices, likely to be 
even faster if natural gas is deregulated. 

As of October, 1977, firm industrial propane prices $.20 below 
natural gas prices per million Btus on the West Coast. In New England, 
however, propane was still $.83 more expensive than natural gas per million 
Btu ' s and is also more expensive in the other regions by amounts ranging 
from $1.67 in Southeast to $.81 in the East North Central region. Especially 
with incremental pricing of new natural gas to industrial users, 



408 

natural gas legislation currently being considered, these gaps will 
quickly be made up. Industrial gas users will find LPG competitive. 

In contrast to gas users, gas utilities and pipelines, with the 
ability to roll higher LPG prices in with lower natural gas prices 
to keep the overall fuel cost to their customers competitive, are already 
interested in LPG for SNG feedstock or peakshaving and standby sources of 
supplemental gas. Propane-air mixtures more than 9.5% propane are not 
combustible, and can be inserted instead of natural gas in pipelines and 
distribution systems. Other sources of supplemental natural gas are 
actively being considered at prices above world-market LPG prices. LNG 
imports projects, such as one expected to deliver natural gas to New 
England at $4.50 per million Btus, (1985 dollars) are being planned 
by the gas industry. Current international propane prices would equate 
to $3.69. Synthetic natural gas from naphtha, Alaskan and Mexican pipeline 
imports and other supplement to natural gas supply are likely to be 
similarly expensive, at least to the Eastern Seaboard region. Given 
the relative advantages on the technical side of LP gas to some of these 
alternatives, it should be able to compete with them in addition to 
filling the needs of its own markets. 

Table I presents the 1975 consumption of LP gases by State and by use. 
The table illustrates the wide use of LPG in all States and for many 
purposes. The decline in LPG sales from 1974 to 1975 was a function of 
higher LPG prices than oil prices, declining domestic production, slow 
economic activity, and warmer weather. One should note, however, that 
the use of LPG (virtually all propane) as utility gas increased abruptly 



409 



.--Sales o£ liquefied pctroleua gate* and ethane by uae, excluding uae In gasoline production, 
by P.A.D. District and State: 1975 and 1976 



(Thousand gallona) 



P.A.D. Dlitrlcc 
and Stat* 


Residential 
and cooaarclal 


Internal -covbu 9 1 Ion 
engine fuel 


Industrial U 


Utility (as 


Hiscellaneous 
uses 2/ 


Total 


1975 


1974 


1975 


1974 


1975 


1974 


1975 


1974 


1975 


1974 


1975 


1974 


DlfCrlcc I : 

Maryland and District of Coluad>la.. 


37,946 
19,481 
2S4.801 
I92.su 
29,828 
61.432 
49,703 
34 , 201 
47,651 
152,066 
110,949 
104,206 
7,299 
86,494 
27,432 
77,116 
16,339 


36,993 
18.286 
256,558 
179,133 
24,733 
58.334 
46,773 
27.729 
44,725 
139,539 
113,816 
96.120 
6.552 
79,483 
24 , 060 
69,822 
15,274 


2.670 
3,748 
17,508 
11,009 
299 
4,765 
3,M» 

10,145 
12,974 
11.220 
16,210 
2,777 
8,126 
131 
5,939 
1,467 


3,469 
2,367 
20,775 
11,822 
536 
5.733 
4,032 
583 
12,137 
16,209 
12,623 
19.720 
3,652 
9,032 
14 5 
7,041 
1.504 


17,295 
3,274 
13,164 
6,286 
3,890 
8,234 
7.885 
2,338 
34,416 
27,894 
24,917 
59,771 
2,395 
15,731 
693 
15,805 
18,229 


19,736 
1,727 
11,842 
8,424 
3,307 
8.708 
9,016 
2,142 
39,072 
29,706 
23,233 
54 , 542 
3,03} 
17,234 
7 33 
15,191 
26,755 


17 .610 
1,073 
14,384 
3,698 
5,205 
13,553 
22,651 
18,068 
17.570 
4,573 
3,447 
30,930 
5,452 
9,288 
6,683 
18.906 


17,058 
669 
12,674 
2,015 
3,461 
16,993 
16.950 
14,676 
14,742 
3,137 
2,888 
25,555 
3.041 
6,706 
4,524 
13,272 


12,288 
7,64} 
14,220 
61,839 
114 
8,063 
12,748 
5,172 
6,089 
20,389 
89,396 
10,823 
2,978 
12,940 
47 
9,118 


6,820 
5.352 
6,806 
44,666 

4,140 
8,777 
3,590 
1.093 
10,954 
57.446 
5.095 
645 
9,456 
■ 34 
4,168 


87,811 
35,219 
314,077 
277,345 
39.336 
95,047 
96,376 
50,323 
115.973 
217 .896 
239.929 
221.940 
20,901 
132,579 
34,966 
126,864 
36,035 


84,076 
26.401 
310,655 
246,060 
32,039 
93,908 
65,548 
48,720 
111,769 
199.545 
210,058 
201,032 
17,123 
121,913 
29.495 
109,494 
43,533 




1,309,459 


1.237.930 


112,921 


131 ,182 


264.219 


274,451 


193,191 


156.361 


273.657 


171,245 


2,776,574 


2.625,331 


District It; 

District III : 
District IV: 


451 ,868 
329,336 
335.974 
225.467 
184 , 820 
257.899 
298 4 23 
47oi6Q4 
155.299 

58.352 
240,950 
278,072 

98.545 
136.716 
267,054 


441,413 
331,977 
334,735 
218,566 
186,121 
270,751 
315 593 
453i334 
150,413 

57,892 
232,448 
261,249 

90.084 
122,663 
283,121 


50,327 
12,868 

5,461 
37,622 

6,605 

9.657 
10,020 

7!625 
23,887 
157 
16,592 
46,984 

5,811 
12,415 

9,672 


56,555 
13,966 

6,498 
43,072 

6,026 
10.961 
11,811 

9^258 
27.457 
186 
22,618 
51 ,906 

5,611 
13,020 
11.485 


67,063 
20,040 
33,358 
19,846 
19,450 
13,954 
22,475 
16i525 
15,767 
5,468 
31,276 
31,292 
2,571 
7,446 
42,924 


71,552 
19,439 
30,963 
16,756 
25,791 
16.615 
29,164 
19,490 
15.206 
5,351 
30,146 
30,526 
3,722 
6,330 
41,420 


15,685 

12,492 

3,457 
3,567 
10,692 
20^469 
12,211 
2,392 
14,864 

6,626 
3,257 
2,816 


14,141 

11,329 

5,409 
5,645 
8,023 
20^805 
14,635 
3,057 
22.062 

8.820 

2,276 
1,396 


205,287 
132,938 
101.161 
46.644 
6.912 
14.463 
44 . 241 
25|303 
33.906 

6,827 
4,979 
9,262 
1,027 
32,351 


150.779 
60,937 
81,790 
27.827 
3.933 
9.077 
24 . 100 
13|412 
14,307 

4,337 
4 ,862 
6,451 
681 
16,219 


611,230 
495,202 
488,466 
329,579 
221,444 
299,740 
385,851 
540,726 
241.070 
66.369 
312.509 
363,327 
123.057 
160,861 
354,817 


734,440 
446,319 
465,335 
306,221 
229,282 
313,249 
388,691 
515.299 
222,028 
65,485 
311,613 
348,543 
116,688 
144,970 
355,641 


3 789 579 


3 750 370 




292 432 




362,693 


108 7 30 




665 301 




6 00 2 08 9 


5 818 328 


193,499 
255,047 
103,075 
209,051 
62,738 
564,212 


211,115 
295,184 
125,200 
246,063 
79,038 
614 ,368 


8,984 
70,209 
31,775 
48,012 
21,845 
514,022 


10,081 
74.143 
34,870 
56,272 
24,718 
584,187 


9,554 
13,381 
111,943 
16,526 

8,103 
47,226 


9,873 
14.850 
133,494 
20,190 

8,335 
55,652 


234 

7,276 
6.674 


211 

6,528 

5,422 


7,004 
56,956 
43,384 
33,080 
12,943 
72,499 


4.917 
31,611 
22,497 
17,920 

5,775 
35.403 


219,275 
397,593 
290,177 
313,945 
105,629 
1,204,633 


236.197 
415,766 
316,061 
346,973 
117,866 
1,295,032 


1.387,622 


1,570,968 


694,647 


764,271 


206.733 


242,394 


14,184 


12,151 


227,866 


116,123 


10.337.929 


11,701.635 


35!ie2 
48,102 
27,845 
47,432 


148 ,878 
38.832 
50.712 
32.454 
45.164 


2^190 
5,181 
I, 111 
12,013 


20, 328 
2,071 
5,627 
1,083 

12,942 


3,612 
1,956 
4,248 
9,419 
5,677 


2,636 
2,981 
5,006 
5,719 
5,505 


9 ,666 


6,490 


16, 276 
10,407 

10,721 
2,535 


12, 274 
7,975 

6,736 
1 ,799 


190 .4 21 
49,735 
57,531 
49,096 
57,557 


190.606 
51.859 
61.545 
45,994 
65,410 


299,964 


316.040 


39.939 


42.251 


24,912 


21,647 


9,666 


5,490 


39,939 


28,786 


414,440 


415,414 


District V: 


3.391 
26,804 
133,803 
15,830 
15,637 
17,911 
19,959 


4,118 
40,756 
198,078 
23.711 
23,626 
31,472 
33.986 


5,307 
40,392 
2,321 
1,349 
1,301 
3,836 


6,180 
43.845 
2,510 
1,326 
1,537 
4,016 


5,466 
657 
199,864 

J. 702 
3,934 
2,987 


3.145 
926 
151,706 

3,958 
4,847 
3,352 


58.519 
18,462 


47.267 
14,335 

636 


14 , 240 
125,747 

7,360 
5.247 


14,164 
127,639 

8,670 
6.162 


8.857 
47.008 
558,325 
35.513 
20,688 
30.506 
37,039 


7,263 
62,006 
568,535 
40,556 
28.910 
46.726 
48.152 


233,345 


355.727 


54,506 


59,414 


216,610 


167,934 


76,981 


62,238 


152,594 


155,835 


697,658 


977.784 


7,019,989 


7,231.035 


1,162,396 


1,309,750 


1,081,929 


1,069,319 


402,752 


356,848 


1,360.567 


917,702 


20,430,690 


21,5)8,692 



1/ Includes refinery fuel of 520.506,000 gallons in 1975, and ^.13, 658, 000 gallons In 1974. 
2/ Includes secondary recovery of petroleuo, agriculture uses, and use as substitute natural gas feedstock. 

i/ District totals do not equal the sun of State totals because of Che Inclusion In district totals and the axclusloo In State totals of figures for chetalcal, and 



synthetic rubber, to avoid disclosing coopany data. Data for these uses are shown In Table 8. 

Mote: District aales totala differ from the district demands as shown In the Monthly Petroleuo Statcnent due to the addition of estimates for rail and truck Interdlatrlct 
■Dvenents. 



410 

between the two years and was most intensive in the New England and Mid-Atlantic 
States, where delivered natural gas prices were highest. This occurred 
despite the factors that led to an overall decline, and suggests that the 
same independence from most of the domestic market might be shown by utilities 
in the future. 

The bulk delivery system of LPG pipelines and port terminals is shown 

in Figure 1, a map published in a 1973 edition of the Handbook of Butane/ 
1 / 

Propane. Updated information shows several additional water terminals 
intended to receive imports. Those which are major international LPG facil- 
ities are circled as well as starved. These are currently 441 LPG ships 
active in world trade with a capacity of 3.5 million cubic meters. In 
addition, a major LP gas pipeline is being proposed to bring Canadian 
LPG from Alberta and deliver it to points in North Dakota, Minnesota, 
Iowa, Illinois, Indiana, Ohio, and Michigan, delivering the bv^lk of the 
throughput back into Ontario. This Cochin Pipeline which is now beginning 
operations, is also added to this map, and will have a capacity of 75,000 
barrels per day. The map indicates a trend toward more LPG importing 
capability, and a focus of new propane demand in the Northeast and North 
Central States — the area where industrial curtailments of natural gas 
have been worst. 

A major terminal, capable of handling 300,000 barrels of LPG per day 
from a large LPG carriers, is being planned jointly by the Northern Natural 
Gas Company and the Texas Eastern Gas Transmission Corporation at Sabine 
Pass, Texas. The LPG would be mostly put into the Dixie and Texas Eastern 
LPG pipeline, that serve a large part of the eastern U.S. This LPG might 
also be injected into natural gas systems if needed. 

1/ See reference 1 in list at end of section. 



411 



Figure I 




412 

3.3.9.3. Projections . What levels of LPG demands are anticipated 
in the United States over the next several years? How much of these demands 
can be met from domestic sources? 

A 1976 report of Jensen Associates forecast total propane demand at 
330 million barrels in 1980 and 335 in 1985; butane demand at 69 million 

barrels in 1980 and 67 in 1985; and total propane-butane demand at 399 

2/ 

million barrels in 1980 and 402 in 1985. 

A 1977 report by Richard Johnson, The Outlook for LPG, 1977-85, 
estimated total U.S. LPG demand, including ethane and other LPG products 
besides propane and butane, at 48.25 million tons in 1980 (about 579 million 
bbl.) and 55.70 million tons in 1985 (about 668 million barrels). 

Both reports anticipated further decline in domestic production. Jensen 
foresees 1980 U.S. production of 263 million barrels of propane and 40 mil- 
lion barrels of butane, for a total of 303 million barrels, leaving a re- 
quirement for 96 million barrels of imported LPG in 1980; and 1985 production 
of 271 million barrels of propane and 47 million barrels of butane, for 
a total of 318 million barrels, leaving excess demand of 84 million barrels. 

Johnson anticipates 35.1 million tons (421 million barrels) LPG production 
in 1980, leaving 13.15 million tons required (156.6 million barrels) 
to meet projected demand for all LPG's in that year; in 1980, Johnson 
predicts 40.0 million tons (480 million barrels), leaving 15.7 million 
tons (188 million barrels) of imports required. 

Both reports foresee some imports from Venezuela, Canada and Mexico, 
the traditional sources of imports, from 17 to 34 million barrels in 1980 
and from 21 to 24 in 1985. 



2/ Reference 2 
3J Reference 3 



413 

Both reports thus anticipate the need for substantial imports of 
LPG from non-traditional sources. Jensen foresees 1980 imports of 57 million 
barrels of propane and butane, Johnson, 5.8 million tons (about 70 million 
barrels) of all LPGs . 1985 forecasts are 55 million barrels of propane 
and butane by Jensen, 10 to 14 million tons (120 to 168 million barrels) 
of all LPGs by Johnson. 

As significant as these amounts are, equalling from 210 to 641 billion 
cubic feet of natural gas, given certain factors they may prove quite con- 
servative. The growing shortage of natural gas may leave unsatisfied demand 
for clean fuels of as much as several trillion cubic feet, and LPG imports 
may prove to be the most popular or economic means of supplementing gas 
supplies for those users who cannot convert to coal. LPG imports are less 
demanding technically than LNG , are more available on the world market, 
do not tie a purchaser to a given supplier, and are not perceived as being 
subject to the same safety problems that may plague LNG projects. Coal 
gasification is getting a slow start and must overcome a host of technical, 
environmental, and economic problems not faced by LPG imports; even though 
it is a domestic source of gaseous energy, coal gasification will clearly 
be unable to make up the mid-term shortfall of natural gas supply. Exotic 
natural gas sources such as Devonian shale, geopressured gas, and 
Western tight sands gas require technical achievements and long lead 
times — they are unlikely to lessen demand for LPG imports for at least 
10 years. 

In short, LPG demand is relatively open-ended because of the natural 
gas shortages and the uncertainty of timing, quantity, and economics as- 
sociated with the other possible alternatives to natural gas. LPG importation, 



414 

from the users and distribution companies' points of view, may have the 
least technical uncertainty and shortest lead time of any of these options, 
and may become popular. Imported LPG may , in short, be a more available and 
important supplement to domestic natural gas supplies than LNG, SNG, coal 
gasification, Alaskan natural gas, or other more widely reported possibilities. 

3.3.9.4. Sources of New Imports . Millions of barrels of LPG have 
been wasted for years, burned along with flared natural gas at oil wells 
in the Middle East and elsewhere. The demand was not present at a price 
high enough to justify the expensive capture and transportation of these 
fuels. Now, however, the situation is changing. New gas processing capability 
is being acquired by producing nations around the world. Johnson lists 
39 LPG export projects planned or underway in the world. 

Table 2 presents Johnson's calculations of the firm, probable, and 
possible export availabilities of LPG from various areas of the world 
through 1985. All data are in millions of metric tons, each of which 
equals about 12 million barrels of LPG. Thus he anticipates firm avail- 
ability in 1985 of 31 million tons, or about 370 million barrels more than 
is available at present, and possible availability of 43.4 million tons, 
or about 520 million barrels more. 

Most of this exportable quantity will be located in the Middle East. 
There will be a general surplus of available LPG over projected demand at 
current prices. Japan and the United States are essentially the only developed 
LPG market areas, and Japan's need for additional LPG is likely to be modest. 
The large expected international surplus of LPG will therefore seek a market 
in the United States. 

4/ , Reference 3. 



415 



Table II 



Summary of Forecast World LPG Export Availability 



(mn tons) 














107R 


lORO 


19R5 

A V' D 


T** i rm 










Tn H on pqii — AiiQfr*f?1 in 

ill <J L/li C OLcl /lUotlctLLcl 


1 . 1 




3 ^ 


3 9 




6 

\j » yj 


1 T 


14 3 


* 2ft 4 




1 Q 


2 9 


4 2 


4 R 


North Spi 




7 


1 .4 


3 2 


Total 


9 


16 .2 


23 4 


40 3 


X 1 UUilU I C 










Indonesia-Australia 


1.1 


2.3 


3.5 


5.6 


Gulf-Middle East 


6.0 


10.3 


14.9 


29.4 


Africa-S. America 


1.9 


3.1 


4.2 


5.9 


North Sea 




0.7 


1.5 


4.0 


Total 


9.0 


16.4 


24.1 


44.9 


Possible 










Indonesia-Australia 


1.1 


2.3 


3.8 


5.6 


Gulf-Middle East 


6.0 


11.3 


19.3 


32.9 


Africa-S. America 


1.9 


3.7 


4.6 


7.4 


North Sea 




0.7 


1.6 


6.5 


Total 


97o 


18.0 


29.3 


52.4 



Source: Richard Johnson, The Outlook for LPG 1977-85, The Economist Intel- 
ligence Unit Ltd, 1977, p. 20. 



416 

Because of the relatively high transport costs of LPG, compared to 
crude oil, and the surplus over, world demand projected at current prices, 
there is some question as to whether LPG prices can be held at their relative 
levels to oil on the world market. Although OPEC is already looking into 
production agreements and pricing agreements for LPG, the fact that LPG 
is in many cases a byproduct of oil production that is otherwise wasted 
makes such agreements difficult to enforce. The choice to the seller 
is not "sell for less or reduce production " — it is "sell for less or 
throw away." In order to make a number of possible LPG export projects 
possible, producing countries will have to have enough price flexibility to 
allow delivered LPG to meet competition. World market prices for LPG 
may thus drop relative to oil prices, making LPG imports more attractive. 
If LPG prices drop below fuel oil equivalents, imports will mushroom as 
industrial users seek the cheaper, cleaner fuel. 

3.3.9.5. Constraints . A major problem of U.S. LPG imports is the lack 
of deepwater LPG receiving terminals. No terminal in the U.S. can currently 
handle 70,000 cubic meter vessels, and such terminals take three years 
to construct. Most of the existing terminals are equipped to handle LPG 
which is pressurized, but most of the large scale transport instead refrigerate 
the LPG to keep it in liquid state, which only a fe larger facilities 
can handle. If the U.S. is to take advantage of the coming surplus of 
LPG on the world market, additional port facilities must be constructed. 
One such facility being jointly planned at Sabine Pass, Texas, by Northern 
and Natural Gas and Texas Eastern Pipeline Companies will be able to accommodat 
such "supertankers" of the LPG trade. Dredging and specially designed 
ship may enable other ports to accommodate LPG traffic in larger vessels 
than currently. 



417 

Propane distribution in the U.S. has followed a similar pattern to 
natural gas — largely produced in the Texas-Louisiana-Oklahoma area, and 
sent north and east to the Midwest and Southeastern States, mostly via 
pipeline but also via rail and water. As domestic sources decline, imports 
of LPG can be brought in the Gulf region to feed this traditional market, 
and along the Eastern and Western seaboards to provide clean fuels to users 
no longer able to obtain natural gas and unable to convert to coal. The 
quantity of such imports will depend on a number of factors, most importantly 
the relative price to users of LPG and alternative fuels, natural gas 
pricing policies, the protection afforded to traditional LPG users, 
the success of other projects to provide alternate fuels to natural gas, 
and world oil prices. 

Safety of LPG imports is another factor. Although handled for years 
with an excellent safety record, LPG is highly volatile and flammable and 
certain atmospheric mixtures can be explosive. The heat content of LPG 
is greater per unit than that of natural gas. A major spill of LPG on 
water would form a heavy layer of gas vapor which could spread and dis- 
perse slowly. In a populated area an intense, widespread conflagration 
could conceivably occur. Such accidents have taken place on land, for ex- 
ample, following a derailment in Decatur, Illinois, but maritime accidents 
of a severe nature have not occurred. Nonetheless, LPG imports would carry 
many of the risks of LNG imports, which are under intense safety scrutiny, 
and safety questions would clearly come to the forefront if there were an 
LPG accident. Large scale LPG imports have the potential to give rise to 
public concern over their own safety. 

24-786 O - 78 - 28 



418 

3.3.9.6. Other Considerations . The market will determine the likelihood 
of LPG imports. As a major factor affecting the energy market, government 
regulation will also have much to do with the exent to which the anticipated 
international surplus of LPG is tapped by U.S. fuel users for traditional 
purposes or new purposes given impetus by the natural gas shortage. Congress, 
in its structuring of oil and natural gas regulation, should be aware 
that its activities will also affect the flows into the United States 
of energy in the form of overseas LPG. It is unlikely that this traffic 
will expand enormously in the next two years, but between 1980 and 1985, 
rapid expansion of LPG import is likely to occur due to an international 
surplus of LPG, with the continued decline of natural gas production in 
the U.S., the tightening world situation in crude oil, and perhaps dropping 
relative prices occasioned by the surplus. 

The aspect of dependency on insecure sources of LPG would be no 
different than for crude oil or LNG. Much of the new imports would prob- 
ably come from the Middle East, and would be subject to political considera- 
tions, although some experts believe that sufficient LPG will be available 
from more secure sources to meet even these large U.S. vessels. The surplus 
available and its link to crude oil production would probably result in 
political interference with LPG trade at worst no greater than that in 
crude oil, and possibly much less. 

Perhaps the major consideration for Congress in connection with LPG 
import plans is the current lack of any regulatory structure in place to 
deal with what may become a popular energy alternative. LPG imports are 
currently allowed to traditional customers by the Energy Regulatory 



419 



Administration (successor to FEA) . LPG prices falling relative to fuel 
oil prices or widespread use as a natural gas supplement would find a 
Federal Government unprepared to deal with the policy implications. 



References 

1. Clark, W.W. Editor. Handbook/butane, propane gases. Published by Butane, 

Propane News, Inc. Arcadia, California, L973 . 2 Vols. 

2. Jensen Associates. Forecasts of U.S. propane and butane supply and demand 

to 1985. Boston, Massachusetts. Sept. 1976. 56, 22 pp. 

3. Johnson, Richard, The Outlook for LPG, 1977-1985. The Economist intel- 

ligence unit, Ltd. London. 1977 62 pp. [EIU Special Report no. 44] 

4. McClanahan, D.N. and Stowell, K.O. Propane transportation 1974. 

Prepared for Texas LP Gas Association and Nat ' 1 LP Gas Association. 
June 1976. @20 pp. 



5. National LPGas Association. 1975. LP-Gas industry market facts, Oak Brook, 
Illinois, 1976. 33p. 



420 

3.3.10 Cargo Preference Issues * / 

Cargo preference, an indirect subsidy, is the practice of reserving 
a specific portion of a particular trade for vessels of a nation-state by 
regulation. While the United States has utilized this concept to an 
extent in relation to Government-financed cargos, the concept of applying 
this practice to energy transportation, particularly oil import trades 
has received growing attention at the national level in recent years. The 
issue is whether to reserve a portion of the oil import trade for U.S. 
tankers . 

3.3.10.1 Background . Earlier discussion in Volume I noted that 

some 7% of the 6.83 billion barrels of imported petroleum liquids 

1/ 

is carried on U.S. bottom or flag vessels. These imported petroleum 
products and crude oil are vital to the domestic energy petroleum 
system. Coal export amounting to 1.6 quads (66 million short tons) 
is the only other international energy trade of note. Almost all coal 
exports are carried on foreign bottoms with a fraction of a percent 
on U.S. bottoms, basically representing defense shipments to Germany. 
Neither oil export nor coal imports are important in discussion of 
cargo preference since those specific trades are marginal. Map 8 displays 
the movement of oil imports with the heaviest import traffic concentrated 
around the New York- Philadelphia and Galveston-Houston areas. Map 
No. 11 displays the crude oil movements, also showing what portion 
of the local input to refineries is foreign. The heaviest input 

*/ Prepared by Martin Lee, Analyst, Environment and Natural Resources 
Policy Division. 

1/ Vol.1, p. 155. 



421 

of foreign petroleum appears in the New York- Pennsylvania areas, but inland 
refineries such as those in Indiana and Missouri derive at least 25% of their 
input from foreign oil. Coal export movement is shown by Map. No. 4, with 
almost the entire export trade moving from Hampton Roads. What is more 
important about these movements is the oil import trade and the dependence 
of the domestic system on foreign input. 

The United States Merchant Marine has declined greatly in numbers 
and moderately in dead weight tonnage. Below are some comparative 
figures demonstrating this decline in relation to the U.S. Tank Ship 
Fleet : 



Year No. of Ocean Dead Weight Tonnage Percent of 

Going Tankers of Fleet World Total 

1945 780 11,283,652 55.9 

1955 490 7,989,500 20.8 

1965 410 8,733,500 9.6 

1974 306 10,236,221 3.6 

2/ 

Thus U.S. total dead weight tonnago has remained relatively the same 
even though U.S. import of crude prcdui. s has increased tremendously. In 
1960 crude imports amounted to 1.8 miliX'jn barrels per day and reached 7.3 
million barrels per day ii In light of the increased demand for 

foreign oil, the decline of the U.S. tanker fleet takes on greater proportions. 

IJ Department of Transportation. Energy Statistics. Washington, U.S. 
Govt. Print. Off. 1976. p. 12 

_3/ See , Federal Energy Administration. Energy in Focus, Basic Data. 
1976 



422 

The United States, the greatest importer of petroleum, stands tenth among 
maritime nations. This decline is at the basis of the cargo preference 
argument, with most advocates viewing cargo preference as a method to 
reverse this downward trend. 

Coal export trade has not been widely mentioned as a possibility for 
application of cargo preference (except for the current military cargos). 
However, when the coal reserves of the United States are viewed in relation 
to the future needs of Europe and certain parts of Asia, and the proven 
reserves of petroleum in the world, this particular export trade presents a 
possibility of growth. 

The decline of the U.S Merchant Marine has been obvious for three 
decades and congressional concern has been exhibited for equally as long. 
For the most part this concern was applied to the break bulk fleet and not 
to the tanker fleet. Cargo preference legislation was first passed by the 
Congress in 1904, in the form of the Military Transportation Act of 1904 
requiring all armed forces cargo to be carried on U.S. vessels unless the 
rates were unreasonable. Public Resolution No. 17 of 1934 (73rd Congress) 
expressed the sense of the Congress that all Export-Import Bank financed 
shipments be carried aboard U.S. vessels. It was the Cargo Preference 
Act of 1954 which first exhibited Congress' real concern with the then 
serious decline of the U.S. Merchant Marine. This statute, an amendment 

A/ 

to the Merchant Marine Act of 1936, required that 50% of all goods bought, 
sold, or provided by the Federal Government be carried by U.S. vessels. The 
combined provisions are worth mentioning for their comparative experience 

4/ 46 U.S.C. 1241, Merchant Marine Act of 1936, Sec. 901 (b)(1). 



423 

with the cargo preference concept, but actually have had little effect 
on the energy transportation system or the oil import trade. 

It was the 93rd Congress which first seriously considered cargo pref- 
erence for oil imports and passed the Energy Transportation Security Act, 
which was later vetoed by President Ford. The Energy Transportation Security 
Act would have required that 30 percent of all oil imports be transported 
on U.S. flag commercial vessels. The President vetoed this legislation on 

the grounds that such action was inflationary and would harm the shipbuilding 

5/ 

industry's ability to meet Navy shipbuiding schedules. Similar legisla- 
tion was introduced in the 94th Congress, but received no action. On August 
2, 1977, the House Merchant Marine and Fisheries Committee favorably reported 
H.R. 1037, as amended, which provided that 4.5% of total American water- 
born oil imports be carried by U.S. flag tankers, with the allocated share 
increasing annually by one percent to 9.5 percent in 1982. A number of similar 
bills are before the Senate. 

H.R. 1037, as amended in Committee, was brought to the floor on October 19, 
1977 where it was defeated by a recorded vote of 165 to 257. During the 
course of debate on this proposal, two significant amendments were accepted. 
One would have placed a ceiling on rates for cargo preferred oil, while 
the other would have allowed for the utilization of foreign-built tankers 
in carrying cargo preferred oil. 

The issue most basic to the adoption of a cargo preference policy ap- 
plicable to the oil import trade is the cost factor. There are differing 

V Weekly Compilation of Presidential Documents, Vol. II. Number 1. 
Dec. 30, 1974, p. 5. 



424 

estimates of what cargo preference has cost the government under past pro- 
grams and what it will cost the consumer of petroleum products if legislation 
similar to the Energy Transportation Security Act of 1974 were to be enacted. 
Jantscher ( Bread Upon the Water ) makes the argument that past cargo preference 
programs have indeed cost the U.S. taxpayer much more than foreign or non- 

U.S. bottoms would have cost. He states that Military Sealift cargos alone 

6/ 

added some $3.8 billion to military shipping costs between 1952-1972. 
Other cargo preference programs under A.I.D. and even donation programs 
added substantial costs. However, some of the speculation over the costs 
of past cargo preference programs may not be totally relevant in discussion 
of cargo-preferred oil imports. Costs, if any, for that particular pro- 
gram would be borne by the consumer in higher energy prices. During the 
legislative activity surrounding the Energy Transportation Security Act 
of 1974, several estimates (Import prices) were made, including: in- 
creases of 0.79 cents per oarrel by the oil companies, .0035 cents per 

barrel by MARAD and a savings of 0.68 cents per barrel by an independent 
7/ 

economist. Some legislation proposed in the past has sought to exempt 
oil arriving on U.S. bottoms from the current 15c per barrel license fee, 
with the resultant savings passed on to the consumer. 

The recent legislative activity on cargo preference brought to the 
surface the variety of cost estimates received in the past and the '.-fide 
range of methodologies and estimates received. The General Accounting 
Office (GAO), in response to a congrecsronal request, prepared an 

6^/ Jantscher, Gerald R. Bread upon the Waters, p. 88. 
7/ See: S. Kept. 93-1031., p. 12 



425 

analysis of the estimate received, the methodologies, and GAO's own 
estimates received on the transportation cost differentials had been:— 



Cents per Gallon 



Organizat ion 



1.2 



Marine Engineers Benevolent Assoc. 



1.6 



Maritime Administration 



2.8 



Federation of Controlled American 



Shipping. 



GAO , using a somewhat different methodology, offered estimates on transporta- 
tion costs between 1.8 and 2.3 cents per gallon. In estimating the annual 
costs for cargo preference, GAO utilized the mid range figure for import 
price differentials and estimated a cost of approximately $240 million 



a year. This amount would, however, vary with the amounts imported. 

Cargo preference for oil imports has many international implications 
as well as implicatons for private U.S. enterprise. Congress has for 
many years regulated aspects of the ocean transportation of goods, to an 
extent, although there are certain regulation activities beyond its con- 
trol. Enactment of cargo preference in the past has involved only 
government impelled or initiated cargos , while cargo-preferred oil imports 

^/ General Accounting Office. Costs of Cargo Preference. Washing. GAO. 



9/ 



Sept. 9, 1977. p. 9 



9/ Ibid., p. IV. 



426 

would involve a host of new actors including numerous foreign entities 

as well as every consumer of the services of the national energy transportation 

system. 

3.3.10.2. Analysis . Implementation of cargo preference policies 
in the oil import trade does involve a number of energy policy problems, 
both general and specific. The focus of this report is to examine 
national energy transportation as a system, and the feeder for much 
of the domestic oil transportation system is the foreign oil import 
trade. Any regulation of this input to the system would affect pipelines, 
refineries, rails, barge and truck transportation of petroleum. There 
is no substitute for the ocean transportation of imported oil. The 
United States is now dependent for 50% of its petroleum from foreign 
sources, most of which enters through East Coast ports as indicated 
on map No. 11. Continuity in terms of flow and price are two major 
concerns related to this particular energy transportation issue, expecial- 
ly in view of the "inland" dependence on the feeding of foreign oil into 
the system at East Coast ports. 

This continuity argument sometimes is referred to as a national security 
argument -demonstrating our dependence on foreign sources and the political 
instability of certain foreign nations. Proponents of cargo preference 
suggest that if some 30% of our imported oil was carried on U.S. bottoms, 
the energy transportation system would at least be assured of some pro- 
tection from disruption of service. Combined with the "Effective 
U.S. Control Fleet" (foreign-registered, but U.S. -owned ships which 
the U.S. would claim in time of war or other necessity), the U.S. 
could possibly keep disruption of oil imports to a minimum. 



427 

Some would argue that the national security argument is the only 
argument for having a merchant fleet at all. Supporting this national 
security argument in part was the 1974 Arab oil embargo which demon- 
strated the vulnerability of the energy transportation system to disruption 
as considerable confusion was caused. On the other hand, the major oil 
companies spread the impact of the embargo out among all oil importing 
nations and thus substantially lessened the impact on the United States, 
demonstrating the fact that an embargo cannot be fully effective against 
the United States. 

As a Nation, we do pay for the utilization of foreign transportation 
for our imported oil, adding sustantially to our balance of payments. 
The use of U.S. bottoms would help the U.S. balance of payments. Other 
possible advantages include boosting employment in both the ship construc- 
tion and operation industries, as well as providing greater control over 
the environmental impacts of ships carrying oil in U.S. waters. 

But at the heart of all these arguments is the question of whether 
we as a Nation are willing to pay for stable oil delivery from foreign 
nations through guaranteeing that a percentage of that oil arrives on 
U.S. bottoms which are more expensive to build, operate, and which 
may result in a higher costs of petroleum products. Economically, the 
U.S. fleet is already more expensive than foreign fleets, as Jantscher 
exhibited, with the high cost associated with the traditional operational 
subsidies, construction differential, and tax subsidies. 



428 

To make this decision, data from many different sources is required. 
Perhaps no greater "knowledge vacuum" exists than that which surrounds 
foreign shipping. U.S. agencies cannot require foreign shippers to sub- 
mit data and most shippers conduct negotiations in secret due to the 
highly competitive nature of ocean shipping. To make a comparative 
analysis of this issue more data may be needed since the few studies 
(see references) compiled in recent years have readily admitted difficulty 
in this area. The 1970 Merchant Marine Act centered some cargo preference 
responsibilities in the Maritime Administration, but various data needs 
remain. 

If Congress does not pass legislation specifically aimed at this 
issue, there are alternatives which might address these problems. One 
is the use of bilateral agreements either through conferences or directly 
with major oil producing nations. In the 1972 wheat agreement with the 
Soviet Union and the Brazilian coffee agreement this concept was applied. 
Such an agreement could be possible with major oil producing nations 
especially in light of the fact that some of them are also interested in 
bolstering their own merchant marine. The Arab Maritime Petroleum Transport 
Company (AMPTC), for example, recently made a number of purchases of surplus 
tankers in an attempt to further control not only production but also 
transportation of oil. 



429 



References 

Heine, Irwin. The United States Merchant Marine — a national asset. 
Washington, National Maritime Council. July 1976, 205 p. 

Jantscher, Gerald R. Bread upon the waters — Federal aid to the maritime 
industries. Washington, Brookings Institution. 1975. 164 p. 

Silberman, Ralph Michael. "Cargo preferences: the United States and the 
future regulation of the international shipping." Virginia journal 
of international law. Summer 1976. 

U.S. Congress. Senate. Committee on Commerce. Energy Transportation Security 
Act of 1974. Senate report 93-1031 on H.R. 8193. July 25, 1974. 
Washington, U.S. Govt. Print. Off. 66 pp. 



U.S. General Accounting Office. Costs of cargo preference. Washington, 
General Accounting Office. September 9, 1977. 44 p. (PAD 77-82) 



430 

3. 3 n INTERNATIONAL PIPELINE TREATY* 

In January 1977, a U.S. -Canadian transit pipeline treaty was signed. 
The treaty will not enter into force until ratified by both countries. 
Hearings were held in .lihe Foreign Relations Committee on June 7, 1977, and 
the U.S. Senate ratified the treaty on August 3rd. The Canadian Government 
in May 1977 took the first step toward ratification by finding that the treaty 
did not conflict with existing statutes. The treaty would confirm to both 
countries a regime of non-interference and non-discrimination for transit 
pipelines carrying oil and natural gas for one country across the territory 
of the other. Because of the huge cost of building pipelines through Arctic 
areas, inter-governmental assurances regarding noninterference with and 
nondiscriminatory treatment of hydrocarbons in transit are deemed necessary 
if investors are to come forth with the substantial capital which will be 
required for such projects as the transportation of Alaskan natural gas. 
Current legislation requires the President to select and the Congress to 
approve a natural gas pipeline route during 1977 for transporting the Artie 
gas south. One major issue is whether the subject treaty adequately limits 
or restrains the taxation and regulatory authority of Canada and its 
provincial governments. 
3.3.11.1. Background . 

In the Trans-Alaska Pipeline Authorization Act of 1973 (Public Law 93-153, 

November 16, 1973) the Congress specifically requested that the President 

initiate negotiations with Canada 

--to determine that Government's willingness to permit the construction 
of a pipeline across Canada for the transmission of oil and gas 
from Alaska, 



*Prepared by R. E. Sullins, Foreign Affairs Division 



431 



--to ascertain the need for intergovernmental agreements for this 
purpose and, 

--to determine the terms and conditions which might be applied to 
operation of such pipelines across Canada, 

Negotiations with Canada were begun in November 1974. Early in the 
negotiations it became apparent that neither the Canadian nor the U.S. 
Government was prepared to take a position on the competing proposals for 
construction of natural gas pipelines from the Arctic. At issue is some 26 
to 100 trillion cubic feet of recoverable natural gas in the Prudhoe Bay area 
of Alaska's North Slope;!/? trillion cubic feet of proven recoverable natural 
gas from Canada's Mackenzie River Delta/Beaufort Basin area, ^and the 
potential for much more; and the question of whether Canada and the U.S. will 
decide to pipe this Arctic gas south together or separately. Three competitors 
are seeking governmental approval for pipelines that would carry the gas to 
the lower 48 states. Two of the projects--Arctic and Northwest--would run 
through Canada. The Arctic line would pick up Canadian gas along the way and 
deliver the gas to both U.S. and Canadian customers. 

Both parties therefore agreed to focus on a general agreement, to cover 
all existing and future transit pipelines, which would provide reciprocal 
government-to-government assurances with respect to noninterference with and 
non-discrimatory treatment of hydrocarbons in transit. 

In January 1976, the negotiators reached agreement on a draft treaty. 
In May, the Department of State made the draft public and invited comment. 
T 

Twenty-six trillion cubic feet of natural gas reserves have been proven. 
Ihis represents in excess of 10 percent of the proven natural gas reserves 
in the United States. The Department of the Interior has concluded that the 
potential reserves can be conservatively estimated to exceed 100 trillion 
cubic feet. 

2 

These natural gas fields, discovered in the early 1970s but not being 
recovered at present, represent about 14 percent of Canada's proven reserves. 



432 

Subsequently minor revisions were made to clarify the provisions concerning 
the authority of provincial governments to levy taxes on U.S. bound gas. 

In October the Alaska Natural Gas Transportation Act of 1976 (Public Law 
94-586) was enacted. This Act established an expedited process so that the 
President and the Congress can make a decision on one of the three pipeline 
proposals in 1977. The Act sets various timetables for 1977; May 1 for a 
final recommendation for the Federal Power Commission on one of the three 
competitive proposals; July l-'^for a decision by the President; and 60 days 
later for a congressional joint resolution of approval. The Act attempts to 
restrict legal actions— which held up the Alaska oil pipeline for 4 years--by 
limiting judicial review of the Presidential decision to questions of con- 
stitutionality of the legislation. Finally the Act directs the President to 
finalize any negotiations with the government of Canada prior to July 1977 
so that arrangements can be immediately concluded if Congress approves the 
President's decision. 

Although the need for a pipeline to carry Alaskan natural gas has been 
the major project motivating negotiations, the treaty applies to existing 
pipelines through the United States in Maine and the Upper '.idwest on which 
Canada depends for oil, and would also be important in consideration of 
future proposals for distribution of the Alaskan oil surplus from the 'west 
Coast, two of which involve Canadian pipeline legs. A Tenneco pipeline to 
bring regasified LNG imports from a Canadian port has also been proposed. 

The proposed treaty signed in January 1977^ contains the following 
basic elements: 

— It is general, covering all existing or future pipelines, which 
transit the territory of each party, carrying all forms of 
hydrocarbons including crude oil, petroleum products, natural 
gas, petrochemical feedstocks and coal slurries; 



The President is authorized 90 additional days if he selects a system for 
which no required final environmental impact statement has been approved. 



433 



--It does not itself provide for approval of any existing proposals 
to construct a transit pipeline across the territory of either 
country, but it makes provision for possible protocols on speci- 
fic pipeline projects; 

--It provides for reciprocity or symmetrical application to both 
parties; 

--It provides a guarantee of throughput, by which public authori- 
ties in both countries are prohibited, except under specified 
emergency circumstances, from interfering with or impeding 
hydrocarbons moving in transit pipelines; 

--It provides for nondiscriminatory treatment which would ensure 
that public authorities in both countries would be prevented 
from discriminating against transit pipeline with regard to 
taxes and other monetary charges; 

--It assures "in bond" treatment for hydrocarbons moving in 
transit pipelines; 

--It ensures the jurisdiction of normal regulatory authorities 
over transit pipelines; 

--There are provisions for equitable sharing of pipeline capacity 
in the event of emergencies on a predetermined basis; 

--It provides for arbitration in the event of disputes v/hich 
cannot be resolved by negotiation; and 

--The treaty is of long duration--35 years--and may be terminated 
then only if a 10-year notice is given. 1/ 

3.3,11.2. Analysis . 

Is the proposed treaty responsive to the provisions of the 1973 Act? 
The Act specifically requested negotiations be initiated with Canada to deter- 
mine that Government's willingness to permit the construction of a pipeline 
across Canada for the transmission of oil or gas from Alaska. The Department 
of State contends that the proposed treaty is responsive to this mandate inasmuch 
1 

U.S. Congress. House. Committee on Interstate and Foreign Commerce. 
Hearings, 94th Congress, 2nd Session on S. 3521 and other identical bills. 
May 17-19 and August 6, 1976. Washington, U.S. Govt. Printing Office, 
1975: p. 151. 



24-786 O - 78 - 29 



434 



as the treaty confirms the willingness of the Canadian Government to 
consider giving approval for a pipeline. However, in late February 1977 
Prime Minister Trudeau informed the Canadian Parliament that the Canadian 
Government had not promised the U.S. that Canada would allow construction of 
a natural gas pipeline from Alaska through Canada to the lower 48 states. 
He said that the Canadian Government had only pledged to give the U.S. an 
answer by September 1977.-^ 

For the Prime Minister to have done otherwise would have been contrary 
to the Canadian regulatory process. Two proceedings regarding the pipeline 
proposals have been conducted. The first, a regulatory proceeding, by 
Canada's National Energy Board (NEB)— / was to decide whether construction of 
any pipeline is in Canada's national interest, The Board decided on July 6, 
1977, to reject the Mackenzie Valley pipeline route for natural gas, but to 
give conditional approval to a southern route following the Alcan Highway. 

The second proceeding involved an independent commission— the Berger 
Commission— headed by a Justice of the British Columbia Supreme Court, to 
assess the environmental and socio-economic impact of the proposed pipeline 
projects. The Berger Commission report, issued May 10, 1977, also rejected 
the northern route, calling for a 10-year moratorium on Artie pipeline 
construction. 
1 

The Canadian Government in July 1977 entered into negotiations with the U.S. 
concerning potential terms and conditions that would be applicable to an 
overland natural gas route. 

2 

The NEB has jurisdiction over interprovincial pipeline construction and 
operation and the export and import of gas and oil. Under the Canadian 
constitutional frame work, the federal government has exclusive jurisdic- 
tion over matters affecting interprovincial and international trade and 
commerce. The Canadian Parliament established the NEB and delegated its 
authority over interprovincial pipelines to the Board in 1959. 



435 

The Canadian Government was under pressure from nationalists to delay 
the joint pipeline. They argue that Canada should await the results of 
further exploration of the Arctic islands where 15 trillion cubic feet of 
natural gas has already been found and which might prove a better bet than 
the Mackenzie Delta. A second problem arose over claims made by native 
Indians and Eskimos to some share of the naturjil resources found on their 
native lands. In this regard several senior Canadian Government officials 
indicated that a right-of-way for construction of a pipeline through Canada 
could be granted prior to resolution of native claims. 

Does the proposed treaty adequately restrain the taxation and/or regu- 
latory authority of Canada's federal and provincial governments? The pro- 
posed treaty provides that any taxes or other monetary charges on transit 
pipelines be nondiscriminatory. It also prohibits import, export or transit 
taxes on hydrocarbons in transit. Finally, it specifically prohibits any 
interference with throughout and discriminatory treatment of transit hydro- 
carbons by any governmental authority but does permit normal safety related 
regulation. 

1/ 

Department of State officials have testified that the proposed treaty 
provides the necessary protection with respect to taxation. They point out 
that in the event it is considered necessary to limit further provincial or 
state taxing powers it can be done through negotiation of a protocol to the 
proposed treaty. The group backing the Arctic project have indicated that 
the proposed treaty is adequate and that a separate protocol is not required 
for their proposed pipeline. 

^ U.S. Congress, Senate .Committees on Commerce and Interior and Insular 
Affairs,. Hearings, 94th Congress, 2nd Session on S. Res. 45. February 17, 
1976 . Washingtor\ U.S. Govt. Printing Office, 1976. 620-621. 



436 

Historically the relationship between the United States and Canada 
has been close, complex, and Changeable. Canada's mood currently is 
nationalistic, rather than continental. But it has been so before and that 
has not hindered the development of close cooperation and mutual support. 

Of all the items of discord over the years none has aroused more con- 
cern in the U.S. than Canada's restrictions on energy exports to the U.S. 
starting in 1973. Since the world oil price explosion. that year Canada has 
announced that its oil exports to the U.S. will be phased out altogether 
by 1981; it has placed an export tax on those supplies to bring them up to 
world market prices while keeping domestic prices lower; it has given pre- 
ference to domestic natural gas users over those in the U.S., if supplies 
falter; it has raised the price of its natural gas exports in line with 
equivalent energy sources--the U.S. imports about half of Canada's natural 
gas production; it has refused to sign new gas export contracts and warned 
of possible supply cutbacks; and it has categorically ruled out a continental 
energy policy under which both countries would share their supplies. However, 
the U.S. has succeeded in pursuading Canada to slow down the increase it is 
imposing on its natural gas export prices to bring these up to the cost of 
alternative fuels. But the U.S. has not succeeded in convincing Canada to 
raise its domestic prices to the equivalent level. 

Both the U.S. and Canada have ample incentive to form a successful 
pipeline partnership. Canada's NEB has estimated that unless arctic 
reserves are tapped Canada's demand for natural gas will begin exceeding its 
supply in the early 1980's. Canada has traditionally looked to the U.S. for 
much of its capital requirements although this a matter of current contro- 
versy with the Canadian nationalists who want to change the historical pattern. 



437 

Canada already operates both oil and natural gas pipelines through 
portions of the U.S. Its major Portland to Montreal oil pipeline carried 
about 150,000,000 barrels of imported oil into Canada in 1974, and another 
major Canadian pipeline flows from Alberta through several Mid-Western 
States before entering Canada again at Windsor, Ontario. Also the Ontario 
steel and electric industries have traditionally secured most of their 
coal from Ohio--from mines that are 55 percent owned by the Canadian steel 
mil Is. 

Although there are bound to be recurrent concerns in the future over 
energy and energy transportation questions between the United States and 
Canada, the prospect of reciprocal moves in the event of less than full 
treaty compliance encourages the belief that mutually satisfactory solu- 
tions will be found for such problems. The proposed treaty may go far 
in improving the security of transportation systems for Alaskan and other 
resources being moved to the contiguous 48 States. 



438 



Selected References 



Alaskan Gas Transport, Congressional Quarterly, v. 34, October 16, 1976: 
2995-2996. 

Canada - A Fair Weather Friend? The Economist, August 17, 1974: 50-52. 

Canada Seeks Its Independence From U.S., National Journal, v. 8, No. 31, 
July 31, 1976: 1062-1970. 

Continental Energy Sharing Editorial Research Reports, v. 1, April 5, 
1974: 241-260. 

Greenwood, Ted Canadian-American Trade in Energy Resources. International 
Organization, v. 28, No. 4, Autumn 1974: 689-701. 

Mehlman, William. Gas - the $6 Million Misunderstanding. Commercial 
and Financial Chronical, v. 20, October 20, 1975: 1, 21. 

Metz, Tim. Another Alaska Pipeline in the Works as the U.S., Canada, 

Mull a Joint Venture. The Wall Street Journal, October 18, 1976: 42. 

Scheibla, Shirley. Coming to a Boil: Competition to Carry Alaska 
Gas Heats Up. Barron's, v. 56, Sept. 6, 1976: 11, 14-15. 

The Big Alaska Decision. Who's Going to Get the Gas? National Journal, 
V. 8, No. 51-52, December 25, 1976: 1812-1817. 

U.S. Congress. House. Committee on Interstate and Foreign Commerce. 

Hearings, 94th Congress, 2nd session on S. 3521 and other identical 
bills. May 17-19 and August 16, 1976. Washington, U.S. Govt. 
Printing Office, 1976: 719 p. 

U.S. Congress. Senate. Committees on Commerce and Interior and Insular 
Affairs. Hearings, 94th Congress, 2nd session on S. Res. 45. 
February 17, 1976. Washington, U.S. Govt. Print. Office, 1976: 
38 p. 

U.S. Congress. Senate. Committees on Commerce and Inteerior and Insular 
Affairs. Joint Report on the Alaska Natural Gas Transportation Act 
of 1976. 94th Congress, 2nd session, June 30, 1976. Washington, 
U.S. Govt. Printing Office, 1976: 38 p. 

U.S. Library of Congress.^ Congressional Research Service. A study 
of the relationship between the Government and the Petroleum 
Industry in Canada. Washington, U.S. Govt. Printing Office, 
1975: 75 p. (94th Congress, 1st session. Senate. Document No. 
94-21). 



439 



3.4. ISSUES AND PROBLEMS RELATED TO WESTERN COAL TRANSPORTATION 



441 



3.4.1, The Sulfur Content, Btu Content, and Certainty of Development of 
Western Coal */ 

A large percentage of the coal reserves in the United States are 
located in the West, particularly in the States of North Dakota, Montana, 
Wyoming, Colorado, Utah, New Mexico, and Arizona. According to the U.S. 
Department of the Interior (1976), the total of demonstrated coal reserves 
in the Western United States totals 234 billion tons (See Table 1), or 
about 53.5% of the total U.S. reserves. 

These coal reserves in the Western region of the United States are 
particularly desirable for development for basically three reasons. First, 
the greatest percentage of the coal can be developed by surface mining 
methods. Second the sulfur content of the coal is, on the average, lower 
(by weight) than that the r-^al reserves east of the Mississipi River. 
Third, the majority of the coal reserves in the Western United States are 
located on Fed^^ral lands which, over tn*^ oast ten to 15 years, have been 
leased to mine ^ r> elopers at Uss thaii fair market prices. 

3.4.1.1. Western Sur f ace-Minable Reserves 

Much of th.: coal in ^.be West, especially that in the Eastern Powder 
River Basin, lies near the surface of the ground ?.nd can be easily extracted 
by surface mining methods. Ttiis same coal is relatively thick-veined 
with most beds averaging 30 to 40 feet and some beds as thick as 90 to 
100 feet. In contrast, Eastern beds average five to six feet in thickness. 
Much of the Western coal can be exposed by open-pit mining methods using 
only bulldozers and powered scrapers. These physical characteristics enable 

*/ By Duane A. Thompson, Analyst, Environment and Natural Resources 
Policy Division. 



442 



Table I. 



Demonstrated U.S. Coal Reserve Base, January 1, 1975, 
by Rank and Potential Method of Mining 

[Billion short tons] 



Mining method « , ■ n, • , , ■ • . ■ • -,- .1 

Anthracite Bituminous Subbituminous Lignite Total 

and area 



Underground : 

East of the Mississippi River 7 162 169 

West of the Mississippi River (^) 31 100 131 

Total underground 7 193 100 300 

Surface: 

East of the Mississippi River C) 33 1 34 

W£;st of the Mississippi River 8 68 27 103 

Total surface ) 41 68 28 137 

Grand total' 7 234 168 28 437 



' Total may not add because of rounding. 
^ Less than one-half billion tons. 

Note — Includes measured and indicated categories as defined by the U S. Bureau of Mines and U.S. Geological 
Survey, and represents 100 percent of the coal in place. Recoverability varies between 40 and 90 percent tor individual 
deposits. Fifty percent or more of the overall coal reserve base in the United Slates is recoverable. 

Source; U.S Depaiiment of the Interior, Bureau ot Mines. 



Source: Energy Perspectives 2 , U. S. Department of the Interior, June, 1976. 



443 

operators to lower their stripping ratios (the amount of overburden re- 
moved per unit of coal) and thereby decrease their production costs. 

This type of mining is also less labor intensive and produces ap- 
proximately three times the amount of coal per unit of labor than that 

1/ 

of underground mining. Therefore, western surface mines have several 
major advantages over eastern underground mines. 

Table II also breaks down the regional reserves into underground and 
surface reserves, and indicates that most of the strippable reserves 
are located in the Western United States. The States of Montana and 
Wyoming account for the greatest portion, although underground reserves 
even in these States exceed surface reserves. 

3.4.1.2. Sulfur Content of Western Coal 

Because of the establishment of emission standards by the 1970 amend- 
ments to the Clean Air Act for electric generating facilities independent 
coal mine operators and captive operations of these utilities have 
over recent years, actively pursued the development of mines in the Western 
States where, with the exception of reserves of low-volatile metallurgical 
coal in southern West Virginia, the average sulfur content of coal by physical 
weight as being is generally lower than that of the Appalachian and Midwestern 
States. Arbitrarily, the coal industry regarded any coal with one percent 
or less content of sulfur being weight as being "low sulfur" coal 
and relatively desirable for development. Furthermore, practically 
all of the Government estimates of coal reserves by sulfur content 
are expressed as a function of the contained weight of sulfur in the 
original coal instead of the amount of residual sulfur, by weight, 

1^/ Bureau of Mines, Minerals YearBook, 1974 lists the average productivity 
for surface mines as 33.16 tons per man-day as opposed to 11.3 tons per 
man-day for underground mines. 



444 



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445 

produced in the form of S02 along with a given amount of heat energy. By 
using the first method of estimating coal reserves, the Department of the 
Interior, in its Energy Perspectives II (Table II), concluded that the 
largest volume of low-sulfur coal was located West of the Mississippi 
River, probably in the Northern Great Plains area. 

While this method of calculating reserves by sulfur may have been ac- 
ceptable in the past, it does not conform to the criteria currently being 
imposed by the Environmental Protection Agency for determining the amount 
of sulfur produced by the combustion of coal. This difference is acknowledged 
in Table II in spite of the fact that the Department of the Interior still 
calculated reserves by the old method thereby distorting the reserve picture 
by sulfur content. Volume I of this study (National Energy Transportation, 
Volume I — Current Systems and Movements, pp. 151-152) contains two maps which 
compare the differences in the reserve distribution picture of "low-sulfur" 
coal based on the content of sulfur by weight, and the amount of coal reserves 
based on the content of sulfur per million British thermal units (Btu's). 
The map on page 152 of Volume I illustrates the reserves on the basis of 
the sulfur content by million Btu's. When expressed in the latter fashion, 
the formerly distinct advantages of developing western reserves are somewhat 
diminished since the total reserves of western coal contain fewer Btu's than 
those in the Eastern United States. This conclusion is further enunciated 
by the conclusions of a contract study prepared for the Congressional Re- 
search Service. The study, which was conducted by the Surface Mining Re- 
search Library of Charleston, West Virginia, (National Energy Transporta- 
tion, Volume I — Current Systems and Movements, pp. 534-587) adjusts re- 
serves in the coal-bearing States according to the sulfur content and the Btu 
content, on a county-by-county basis, to indicate the degree of compliance 



446 

of the coal with clean air standards. The question of coal sulfur content, 
by weight or in pounds of S02 per million Btus of coal burned, may be mooted 
by the current provisions of the Clean Air Amendments Acts of 1977. This 
Act casts an entirely new light on the coal reserve picture of the United 
States. The policy of requiring all utilities to install the best-avail- 
able -control-technology (BACT) will eliminate sulfur content as a cri- 
teria in coal selection, leaving primarily Btu content, ash, and distance 
from the mines to the markets to determine the relative economics of 
eastern and western coal. Rather than burn coal which emits less surfur 
either as a function of the weight of the coal or the amount of heat 
energy produced, utilities, if required to clean stack gases in any 
cases, would opt for coal that is closer to their generating stations, 
thereby incurring lower freight costs, other things being equal. This 
development could mean that coal with an higher overall energy content 
would be preferred regardless of its sulfur content. Utilities may then 
favor eastern coal more than otherwise thereby reducing western coal 
production and consequent transportation to the East. 

3.4.1.3. Federal Coal Leasing Policies as a Stimulus to Western 
Coal Development 

The third crucial element in the rapid expansion of the western 

coal mining industry is the relative ease with which mining companies 

acquired Federal coal reserves over the past 10 to 15 years. Because 

the outdated Mineral Leasing Act of 1920 allowed Federal coal reserves 

to be disposed of on a set royalty-per-ton and an annual-rental-per-acre 

basis, the mining industry was able to acquire a total of over 189 million 

2/ 

tons of coal for only about $23.4 million or about 12. 5c per ton 

2/ "Federal Coal Leasing Amendments Act Should Increase Production and 

Public Benefits from Coal Leasing on Federal Land," Natural Resources 
Journal, Volume 16, October, 1976, pp. 1033-1037. 



447 



during the 54 years that elapsed before the passage of the Coal Leasing 
Amendments Act of 1975. 

Although many of the lease sales were held on a competitive basis, 
a great percentage of the leases were ulimately awarded with only one 
company bidding. 

In a 1974 report, the Council on Economic Priorities (CEP) revealed 
that of a total of 236 coal leases awarded, 145 of the leases were awarded 
in action that involved the participation of one bidder (Table IV). Ac- 
cording to CEP "Twenty-five, or 10% of the 242 public coal competitive 
lease sales drew no bidders, and the leases were awarded to the original 
sale applicant without payment of the cash bonus.... In a startling 59% 
of the public coal sales, only one bidder appeared.... The average bid 
for these leases was $3.31 an acre." It is impossible to determine the 
thickness of the coal in question, but assuming an average thickness of 
20 feet and based on the generally accepted weight of 1700 ton per acre 
foot, the bonus bid for 59% of the public lease sales was an infinitesimal 
$0.0001 per ton. 



Table III 



Number of Competitors and Average Bid 



No. of Bidders 



No. of Such Leases 



Average Bid per Acre 




1 
2 
3 



25 
145 
37 
14 



$ 0.08 
3.31 
36.43 
25.61 



4 or more 



15 
236 */ 



112.18 
$16.90 



"l^l For the other eleven competitive leases, sufficient information 
is not available for a listing. 



448 

Table III also shows that when the number of bidders was increased, 
the bonus bid for the privilege of developing Federal coal increased 
drastically also to $112.18 per acre, but still less than $0.01 per ton. 

3.4. 1.4. . Recent Increases in the Development of Western Reserves 
Major increases in coal production have clearly been generated by 
the development of western reserves. According to statistics by the 
Bureau of Mines, a significant portion of the production increases over 
the last five years has come from key Western States. From the period 
from 1972 to 1976, the U.S. Bureau of Mines established the changes in 
coal production as shown in the following tables. 

While some of the States, especially the Eastern and Midwestern 
ones, have experienced declines in production from 1975 to 1976, practically 
all of those in the Northern Great Plains and in the Southwest have substan- 
tially increased their production during the same period. From 1972 until 
1976, the Western States increased their production in the 
f o I lowing amount s : 

Table IV 



Arizona + 246,0% 

Colorado + 70.7% 

Montana + 217.5% 

North Dakota + 67.6% 

(lignite) 

Texas (lignite) + 251.4% 

Utah + 64.1% 

Washington + 56.1% 

Wyoming + 182.5% 



Over the same period, some of the key Eastern and Midwestern states 
increased their production by much smaller amounts and in many cases, 
production actually declined significantly (Table V) 



449 

Table V 



Illinois - 11.5% 

Indiana - 7.0% 

Kentucky + 15.5% 

Ohio - 10.8% 

Pennsylvania + 10.0% 

Tennessee - 22.2% 

Virginia + 8.0% 

West Virginia - 12.0% 



In terms of the actual tonnage, the Western States increased their 
production by 68,237,000 tons while the production of the Eastern and 
Midwestern States declined by 2,965,000 tons during the same five-year 
period . 

Furthermore, in terms of mine size, larger mines are emerging in 
the Western United States. For some years, the largest single coal 
mine in the United States was the River King mine in southern Illinois 
which was owned and operated by Peabody Coal Company. Within the last 
two to three years, however, the River King Mine fell from first to 
sixth place. All of the mines that have displaced it are located in the 
Western United States, with the oldest one starting operations in 1963. 
The number one mine, Decker No. I, started operations in 1972 and is 
currently producing in excess of 10 million tons annually. Of the top 
ten coal-producing mines in the United States in 1976, only two were 
east of the Mississippi River, including the River King Mine in Illinois 
and the Moss No. 3 mine in Virginia. 

3.4.1 .5. Projected Production from the Western States 
Many of the Government projections have emphasized the important con- 
tribution that western coal can make in achieving energy independence. 
The 1974 study prepared by the Federal Energy Administration (Coal Task 
Force) cast two scenarios for increased coal production through 1990. 

24-786 - 78 - 30 



450 

The Business-As-Usual (BAU) scenario "assumed the continuation of all 
current policies that could affect levels of coal production." The Ac- 
celerated Demand scenario "assumed selected changed in policy or practices 
that would permit a greater expansion of potential production." In the 
study, the United States was divided into seven coal-supply regions. 
Estimates for increases in coal supply are keyed to these regions. According 
to the projections made by the Federal Energy Administration, with one 
exception, the largest percentage increases in coal production were 
expected in the region, which includes the major subbituminous and lignite 
deposits in the Northern Great Plains. This region, which accounted 
for 32 million tons of surface mined production in 1973, would be expected 
to produce 152 million tons in 1985 in the BAU scenario, or an increase 
of 375% over the 12 years. The only other region which surpassed this 
projection was the region of the Gulf Coastal States, which was projected 
to increase its lignite production from seven million tons in 1973 to 
43 million tons in 1985, or by 514%. Although the increase is significantly 
larger, the amount of the production is much smaller and because of 
the physical properties of lignite, the impact of this production would 
be much more localized. 

Although the FEA projection and the other studies which predicted an 
overall increase to 1.2 billion tons total U.S. production are now con- 
sidered optimistic, more conservative estimates still predict drastic 
production increases in the Western United States. In its 1976 Study 
of New Mine Additions and Major Expansion Plans of the Coal Industry , 



451 



the National Coal Association indicated that as of that time, the in- 
dustry planned to add 507.9 million tons of new and replacement capacity 
during the years 1976 through 1986: 

Over half of this capacity, or 278.4 million tons, will be 
added west of the Mississippi River. The remainder will come 
on stream in the East with the largest additions planned for 
West Virginia, Illinois, and Kentucky. _3/ 

Of the 423.15 million tons of steam coal expansion, 65.3% is expected 
to be in the West. The Association qualified its projections with the 
following statements. Such increases are only likely if: 

(1) The significant deterioration provisions of pending congressional 
legislation amending the Clean Air Act of 1970 will not be enacted. As 
written, the non-deterioration section would have a devastating effect on 
projected plans. 

(2) Unrealistic Federal surface-mining regulations, such as that 
currently under consideration, will not be enacted. 

(3) A sensible means of complying with the National Environmental 
Policy Act (NEPA) can be developed to allow energy development to take 
place without undue delay. 

(4) Adequate capital will be available to meet the growing needs 
of the industry, kj 

If any of these assumptions should change, tonnage capacities 
now scheduled to come on line could be expected to be delayed or drop- 
ped from the plans of the industry. 

One of the latest studies prepared by the Federal Government on 
the subject of western coal development and one which has been quoted 
extensively by the industry is the spring quarter issue of the Western 



_3/ A Study of New Mine Additions and Major Expansion Plans of the Coal 
Industry, The National Coal Association, August, 1976, p. 1. 

kj A Study of New Mine Additions and Major Expansion Plans of the Coal 
Industry, The National Coal Association, August, 1976. 



452 

Coal Development Monitoring System published by the Federal Energy Admin- 
istration (FEA/B-77/136) , March 31, 1977. The system, which currently 
monitors 83 active western mining operations, contacted each coal 
company in order to determine their projected production from mines in 
the 200,000 ton capacity range or greater. According to the report, "with 
the exception of some 15 mines, all identified future operations are 
optimistically targeted to start up by 1982." 

The figures, however, were obtained voluntarily from industry spokesmen 
and, according to the study, "may represent future production levels desired a 
opposed to future production levels actually under contract at this time." 
Changes in the projected tonnages may occur as a result of changes in 
the contracts. The largest increases are earmarked for Wyoming, North 
Dakota (lignite), and Texas (lignite). Production in the first two states 
is projected to increase at least tenfold while production in Texas will 
probably increase by a magnitude of about seven times. The forecast 
is contained in Table VI. 

In all of the projections made by the agency, however, the ability 
to lease and develop Federal coal is an indispensable element. Given the 
current Administration's desire to stress production of eastern coal and 
the slowness of additional leasing of western coal lands, however, these 
projections may be unduly optimistic. According to the projection, the total 
production from the "logical mining units" including Federal lands by 
1985 will represent an amount equal to two-thirds of the current 1977 
production of approximately 665 million tons. This total is likely to prove 
optimistic. Adding to the likelihood is the Administration's tendency to 
favor the development of underground mines. In addition, if utilities 



453 



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454 

Table VI 



PROJECTED WESTERN COAL PRODUCTION 

(In Millions of Tons) 



1976A 1977 1978 1979 1980 1981 1982 1983 1984 1985 



Alaska 


0.7 


0.7 


0.7 


0.8 


1.0 


1.0 


1.0 


1.0 


1.0 


1.0 


Colorado 


9.4 


10.6 


14.0 


16.8 


20.2 


19.9 


20.3 


20.4 


20.5 


20.6 


New Mexico 


9.8 


12.3 


15.5 


18.7 


22.0 


22.6 


22.6 


22.7 


22.7 


23.7 


Montana 


26.0 


26.7 


28.5 


30.1 


38.0 


49.0 


53.6 


55.1 


56.6 


61.1 


Arizona 


10.4 


10.4 


10.4 


11.0 


11.5 


12.0 


12.5 


12.5 


12.5 


12.5 


North Dakota 


11.1 


13.3 


20.5 


21.1 


22.4 


28.6 


35.6 


36.1 


36.5 


40.1 


Oklahoma 


2.9 


2.9 


2.9 


3.3 


3.7 


3.9 


4.1 


4.3 


4.4 


4.6 


Texas 


13.5 


17.7 


22.3 


27.4 


28.5 


43.0 


44.0 


44.5 


49.8 


53.5 


Utah 


7.7 


13.6 


18.4 


19.3 


22.2 


23.2 


25.1 


25.3 


25.5 


25.9 


Washington 


4.1 


4.0 


4.0 


4.0 


4.0 


4.0 


4.0 


4.0 


4.0 


4.0 


Wyoming 


29.8 


50.4 


73.2 


107.3 


141.4 


170.5 


191.9 


202.4 


212.1 


236.4 


Total 


125.4 


162.6 


210.4 


259.9 


314.9 


377.7 


414.7 


428.3 


445.6 


483.4 



Source: 



The Coal Observer, Dean Witter and Co., Inc., June, 1977, 



p. 



7 



455 

are required to install the best pollution control devices available 
regardless of the source, the indigenous impurities of the coal being 
burned, or the installation cost of the equipment, prudence would dictate 
that the utilities question the economic efficiency of bringing Western 
coal one thousand or more miles to the East when the emissions from 
this coal would have to be eventually removed anyway. The essential result 
of a decision to require BACT on all coal burning installations would be 
to neutralize the sulfur level advantage that western coal may enjoy. 
This has led to suggestions that eastern coal be purchased instead and 
any freight savings applied to the cost of installing the pollution 
control equipment. 

This apprehension concerning the overall increase in the amount of 
western coal production is shared by a recognized authority in the mining 
industry, Mr. Joel Price, a vice-president with the investment banking firm 
of Dean Witter and Company, Inc. In his report on the industry, Mr. Price, 
after reviewing the projections made by the Federal Energy Administration, 
made downward adjustments in the total tonnages expected to be generated 
by the Western States (Tables VII, compare with Table VI). 

Although the differences in the two estimates are not overly significant 
until after 1980 (the difference in 1980 is approximately 10 million tons), 
the two curves draw further apart after that year until, in 1985, the target 
year for both of the projections, the total difference is approximately 
310 million tons. Mr. Price indicated that even his lower 315 million 
ton and 483 million ton projections for 1980 and 1985 respectively are 
only "possible" targets , achievable if the orders become available. (Figure I.) 



456 



Figure 1 . 

Projected Western Coal Production to 1 985 



Millions of Tons 

650 



550 - 



/- 



FEA's WESTERN 
COAL DEVELOPMENT ^.^4 
MONITORING SYSTEM / 
/ 




'DEA/ i VITTER's 
COAL OBSERVER 




1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 



457 



According to Mr. Price: 

Some 25% of the 1980 figures still require environmental 
impact studies, while for 1985 40% needs further permitting 
and approval. The realities are that much of the tonnage 
increment in the 1981-85 period is not committed; absent 
orders, such mines are unlikely to come on-stream or 
operate at a diminished rate of capacity; thus, they tend 
to adjust production targets in both 1980 and 1985 to lower 
levels. _5/ 

The scenario that is cast by the Coal Observer is one in which 
coal produced in the Northern Great Plains moves to the Gulf States in 
order to replace oil and natural gas currently being used for electric 
power generation. Furthermore, this coal could be used for the establish- 
ment of new base-load electric plants to replace proposed nuclear plants 
in the West. 

In the E??t — east of the Mississippi, that is — 23.6 
million tons of western coal were consumed in both 1975 
and 1976. Thvs is expected to expand to 34 million tons 
in 1980 and lo 51 millions tons in 1985. Ustrs are Indiana,. 
Wisconsin, Illinois, (/hio, and Michigan. But the last three 
states have no plar s .-<r further -se of western coal. New 
consumers will be Kississiop; an' Georgia This will 
mean that between 1975 ano. 1985 only 10% of the incre- 
mental western coal burned will be east of the Mississippi. 
The most r^ eiiL FPC study indicated 7%. ()_/ 

In a subsequent issue of the Coal Observer , dr. Price did make 
some adjustments to his original estimates in the future consumption 
of western coal by utilities. The original estimates of coal consump- 
tion by utilities in 1985 totalled 361.3 million tons, which was in- 
creased by 14.5 million tons for the following reasons. Two TVA gener- 
ating plants in Kentucky and Tennessee intend to shift to western coal 



2/ The Coal Observer, June 1977, p. 7. 



6/ Ibid. , p. 7 . 



458 

between now and 1985, a Detroit Edison plant intends to increase 
its consumption of Western coal, by 2 million tons, and a new generating 
facility is planned by four Iowa utilities which could consume approximately 
2 million tons starting at its 1983 completion date. 

3.4.1.6. Conclusion . Regardless of the exact amount of coal development 

which takes place in the Northern Great Plains and other Western States 

over the next 8 years, two things are very evident. First, the present 

Administration is advocating more intensive development of eastern underground 

coal reserves and, second, the coal industry, at least from their financial 

commitments for equipment, appear intent on the development of western 

reserves. In recent weeks. Secretary of the Interior Cecil Andrus has 

7/ 

publicly commented that the Administration does not intend to continue 
coal leasing in the West unless both the surface of the intended leasing 
area along with the minerals are owned by the Federal Government, an 
exception being when the surface is owned by the coal company interested 
in leasing the subjacent Federal coal. This type of policy, along with 
the provisions of the recently enacted Federal Surface Mining Law, and 
the enforcement of BACT provisions of the Clean Air Amendments Act of 
1977 (P.L. 95-95) must surely serve as en encouragement toward the develop- 
ment of eastern underground reserves. Legislation has also been proposed 
that would give the Carter Administration the authority to order utilities to 

_7/ Cecil Andrus, Secretary of the Interior, keynote speech at the National 
Association/Bituminous Coal Research Symposium at Louisville, Kentucky. 



459 

burn locally-produced coal in areas where the mining industry is depressed. 
At the same time, however, most of the current industry literature indicated 
that the industry has no intentions of slowing its pace in the development 
of western reserves. The periodicals covering current developments are 
replete with articles about the erection of giant draglines in the Eastern 
Powder River Basin while others exclaim about various mines that are plan- 
ning enormous increases in output over the next several years. Railroad 
spurs are being laid and larger-than-ever silos for the loading of unit 
trains are being constructed. 

The key determinants of the development of the western coal, and thus 
of the importance of the transportation problems of getting western coal to 
users, will be the decisions concerning leasing of additional Federal lands, 
upon which production projections depend, and the decision concerning the re- 
quired air pollution controls needed for coal burning utilities, which may 
negate the sulfur-level advantage of western coal. Although current expan- 
sion, based on current user commitments, appears to be proceeding actively, 
it is probably a better indicator of future trends that the Administration 
in power has given both of these decisions answers discouraging to massive 
western coal development. Their greater distance from big markets and lower 
Btu contents put western coal at a disadvantage to eastern coal, if the 
same air quality controls are required for both. Combined with the Admin- 
istration's vocalized preference for eastern coal, these factors cause doubt 
as to the likelihood of western coal production in future years in the quanti 
ties anticipated by the more optimistic observers. 



460 

3.4.2. Expansion of Railroad Coal Movement Capacity to Probable 
Western Coal Markets */ 

The projections of substantially increased coal production in the 
West have given rise to questions about the capability of western rail- 
roads to expand sufficiently to manage the increase in traffic. Although 
some studies have suggested that certain links in the system would be 
overloaded, the consensus appears to be that the flexibility of rail 
technology is sufficient to allow for the necessary increase in traffic, 
but that the necessary capital for upgrading the capacity will test the 
financial strength of even the relatively healthy western railroads. 

3.4.2.1. Background . The National Energy Plan projected that pro- 
duction of western coal would grow from 85 million tons in 1975 to 345 
million tons by 1985, 227 coming from the Northern Great Plains regions. 
To some extent, this coal may be consumed in the western region for electric 
generation, and possibly some for coal gasification if work is begun soon 
on facilities. The largest part of 1985 production will clearly be exported 
as coal, however. 

The railroads offer the only viable means of coal movement at present. 
Unless slurry pipelines are built, they will continue to be the exclusive 
means of coal movement from western mines. Even if several slurry pipelines 
are built, the railroads will, assuming the accuracy of the NEP's production 
projections, be required at least to double their 1975 movements. Of course, 
many reviewers have stated that the President's projections are high. The 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 



461 

General Accounting Office, for example, anticipates that actual 1985 pro- 
duction will be less than the national total of 1.2 billion tons the NEP 
has predicted. 

If the question of whether or not railroads can expand sufficiently 
to carry the coal production that will occur can be answered positively 
given the National Energy Plan projections, then it would not be answered 
negatively under other projections. 

What limitations might there be on the physical capability of the 
railroads to multiply their coal movement? Assuming that loading and unloading 
facilities are provided by the producer and customer, respectively, the 
track, rolling stock, and locomotives are what the railroad must provide. 
Often unit train hopper cars are owned by the customer utility, moreover, 
further reducing the railroad's burden. 

The primary question thus boils down to whether the railroads can 
obtain sufficient numbers of hopper cars to carry the coal, enough loco- 
motives to pull them, and can construct and maintain adequate track for the 
movement to occur. The second question is whether the railroads can 
finance this activity, assuming it is physically possible. 

A number of studies have focussed on these questions. All have con- 
cluded that the necessary locomotives and hopper cars could be available 
to the railroads for the traffic. According to the study performed for 
the Electric Power Research Institute by Manalytics of San Francisco, 

"Clearly, aside from the financial aspects, the industry can obtain the 

1/ 

equipment necessary to meet the expanded traffic demands." 



XJ Manalytics, Inc. Coal Transportation Capacity of the Existing Rail 
and Barge Network, 1985 and Beyond. Published by Electric Power 
Research Institute, Palo Alto, California. 94304, p. 6. 



462 

3.4.2.2. Track Capacity . Thus, the question of physical capacity 
is resolved to a consideration of whether the trackage can accomodate 
the probable number of trains between coal producing points and coal con- 
sumers . 

The Manalytics study, mentioned above, generated a substantial con- 
troversy when it was released, because it identifies numerous stretches of track 
which were projected to be overloaded given maximized future projections. 
The Manalytics study did not conclude, however, that this would lead to 
inability of the railroads to handle the traffic, but rather to greater 
shipment expense and time requirements because of the necessity to employ 
longer routes avoiding the bottlenecks. 

Nonetheless, criticism from railroad interests was strong, alleging 
that the Manalytics study did not recognize sufficiently the flexibility 
inherent in railroad operations, and obviously concerned that the study 
would provide grist for slurry pipeline advocates' mills. One critical 
report, by Richard J. Barber Associates, Inc., claimed that the Manalytics 
study's assumptions were too high in coal assumed to be moved by almost 
a factor of two, and too low in assumed capacity as a result of focusing 
on too few of the possible routes and omitting the traffic increases possible 
from adding modern signalling technology. On a single line track, according 
to the Barber report, changing the signalling system from manual block 
signaling to centralized traffic control (CTC) can double track capacity. 
Adding sidings and lengthening them as required can lead to gradual expansion 
of capacity. A two-track line with CTC can accommodate as many as 125 



463 

2/ 

unit trains per day. Even with half of these trains running empty 
on return trips, such a movement would equal more than 225 million net tons 
per year of coal delivered-about one third of current national demand for 
coal. Obviously if all of the numerous tracks connected with the western 
coal regions were to receive such upgrading, the resulting track capacity 
would dwarf any likely demand for years. 

3.4.2.3. Financing Larger Capacity . The costs of expanding rail 
capacity to serve the greater production of western coal will be roughly 
parallel to the increase in that production. Thus the wide range of un- 
certainty concerning the demand for western coal, which will dictate the 
production of western coal, puts the necessary investment into equal un- 
certainty. 

Another truism is that the construction of additional rail transporta- 
tion capacity to move coal requires less time from inception to completion 
than either additions to production by opening a new mine or addition to 
demand by building a new power plant or major industrial boiler. Thus the 
transportation requirements will be precisely known, and could be provided for 
before the transportation is required. Presumably, then, the uncertainty 
over the general financial requirements for upgrading rail capacity will 
not play a critical discouraging role, because the investment will be 
sought on an ad hoc, as-needed basis, with sufficient time to make arrangements 
after production and consumption commitments are made. 

Ij Richard J. Barber Associates. The Railroads, Coal and the National 
Energy Plan: An Assessment of the Issue. Washington, D.C. 1977. 
Prepared for six major western railroads, p. 37. 



464 

As the capacity of the railroad industry to provide the needed rolling 
stock and locomotives is more certain than is the capacity of the track to 
carry the necessary coal, so the railroad ability to finance the needed 
cars and locomotives is more certain than their ability to finance the 
necessary upgrading of their rights-of-way. The Barber Associates re- 
port anticipates investment needs of about $4 billion for equipment and 
an equal amount for rights-of-way improvements. 

Equipment trust certificates are generally used for railway equipment. 
Because of the highly mobile nature of the equipment, making it good col- 
leteral, and the good record of the industry in paying for equipment, 
investors are not chary of such trust certificates. While the increase 
in equipment necessary fr coal movement may cause some increase in the 
yield of such certificate, the major coal moving railroads should be able 
to obtain the necessary rolling stock by this means or by leasing, if 
indeed customer-owned equipment is not used. 

As individual railroads approach capital markets seeking money with 
which to expand track capacity, however, the different nature of the investment 
will cause a different reaction from investors. Track and right-of-way 
cannot be repossessed and sold; it is the condition of the company that 
gives them their value. The railroads will need to offer returns on investment 
competitive with those offered by others companies, including the coal 
companies and electric utilities providing the traffic, if they hope to 
find the financing. Although the western railroads which will be moving 
a lot of coal are generally in better financial shape than most railroads, 
it is not clear that they have the current profitability to be able to 
obtain the requisite investment, much less to finance the track maintenance 



465 

and improvements internally. According to the Barber Associates report, 

3/ 

their rate of return on net investment was only 3.6% in 1976. Eastern 
and southern railroads fared worse. 

The Barber Associates report estimates that the total capital invest- 
ments required to be made by railroads to 1985 equal about $40 billion, of 
which coal-related investments will conservatively require ten percent. 
This would amount to twice the recent annual level of capital outlays. 

The logical conclusion is that either (I) railroad profits must improve 
to attract the additional equity investors or make new debt affordable, or 
(2) help with financing will have to be provided by the Federal Government, 
producers, customers, or others. The first would be preferable to the se- 
cond from the railroads' viewpoints, and is the way the system should presuma- 
bly work. But shippers of other commodities may be reluctant to pay the high 
rates necessary to make the railroads profitable enough to build for coal 
movement, even if they benefit marginally themselves from the increased 
capability. On the other hand, loading the increased revenue requirements 
on coal shippers may make potential alterntives to rail movements much more 
attractive . 

Investors, of course, look not only at current profitability to assess 
their investments, but at prospects for the long term. Uncertainties implicit 
in such proposals as coal slurry pipelines, which might take traffic that 
a railroad has expanded to accommodate, will be reflected in the cost of 
available capital. Long-term rail contracts may be one possible means of 
improving certainty and f inanceability of improvements. (See 3.4.4.) 

3/ Ibid. , p. 48. 
4/ Ibid., p. 57. 

24-786 O - 78 - 31 



466 

3.4.2.4. Cone lusion . IL is well known that the nation's railroads 
are not the most healthy of corporations. Several major lines have been 
forced into consolidation and bankruptcy. Those which will be expected to 
move the largest part of western coal are healthier than average, but also 
do not compare well to most business and industries. It appears that the 
physical capability to move the projected volumes of coal from western 
mines can be achieved. That improved capacity would normally be financed 
largely in the capital markets, and may probably require better returns 
than the railroads can currently provide to investors. 

It is conceivable that the coal movement facets of rail operations, 
or those rail companies which will move most of the projected coal, could 
receive some targetted assistance in the form of rate boost or special 
aid that would enable the coal-related investments to be made even while 
the general fortunes of the industry declined. But the railroads would 
obviously prefer that the additional coal-carrying capability be made 
financeable as part of a general improvement in rail industry financial 
health. 



467 

3.4.3, Local Impact of Coal Unit Train Traffic */ 

Unit-train traffic, stimulated by the proposed development of coal 
in the Northern Great Plains, threatens increas ingdisrupt ion of the 
lifestyles in the communities bordering the major rail-lines out of the 
coal fields of Wyoming and Montana. 

3.4.3.1. Background . Since its inception, railroad transportation 
has had an impact on the towns and land it crossed. Even the earliest 
locomotives had cow-catchers installed on the front for the purpose 
of physically removing farm animals from the railroad tracks as the 
engines passed by. Furthermore, the earlier models of locomotives 
were responsible for starting numerous fires along the rights-of-way 
with sparks emitted from the smoke stacks. From the time that trains 
grew to even a fraction of their present size, they have overpowered 
horse-drawn and smaller vehicular traffic. Trains are extremely heavy, 
and cannot be stopped in nearly as short a space as an automobile, 
bus, or pedestrian. Consequently, other traffic, with the exception 
of other trains or ship traffic, has had to yield to railway traffic. 

Trains can also be a frustation to street and road traffic when 
they move slowly through cities and towns that do not have overpasses 
or underpasses. This is worse when the trains are slowed because of 
safety concern in a populated area or for the purpose of switching 
rail cars among sidings, 

*/ Prepared by Duane A. Thompson, Analyst, Environment and Natural 
Resources Policy Division. 



468 

The current increases in coal-train traffic through some of the 
smaller towns and villages in the Northern Great Plains and the prospect 
of even higher rates of traffic caused by projected production increases 
had generated serious concerns of the residents. In addition to the 
negative impact of increased train traffic, some of the communities can 
also look forward to a small influx to the communities of new members 
who will be employed by the railroads. 

Many of the communities adjacent to the rail lines that will be 

carrying the coal, however, have been unaccustomed to high levels of 

train traffic through their communities and many are becoming alarmed 

about the effects of already increasing number of trains bisecting these 

villages at frequent intervals. 

Local government officials have expressed concern over the likelihood 

t 

of certain sections of their cities and towns being cut off from emergency 
services because of coal unit-trains going through the area. Some of 
the environmental impact statements prepared for mines being opened or 
expanded in the Northern Great Plains areas allude to the fact that in- 
creasing coal traffic on the railroads will increase the inconvenience 
and risks of the residents living in the areas through which the coal 
trains will pass. 

Temporary inconvenience and poor travel conditions caused 
during maintenance of the facilities are unavoidable. It is 
impossible to predict the possible increase in train car accidents. 
With the number of trains required per day, the increased probabil- 
ity of these accidents occuring cannot be avoided .l_/ 

1/ Proposed Plan of Mining and Reclamation : Belle Ayr South Mine , 

Amax Coal Company, Coal Lease W-0317682, Campbell County, Wyoming, 
U.S. Department of the Interior, Geological Survey, 1975. p. 157. 



469 

This conclusion is also reached in a MITRE Corporation study which 
was sponsored by the RALI Office of the United States Geological Survey. 
According to MITRE, "Injuries and fatalities to railroad employees and 
the general public can be expected from the operation of unit trains." 
These accidents, which are classified by the Department of Transportation, 
Federal Railroad Administration as being either "train accidents," "train- 
service-accidents," or "non-train-accidents," are defined in the following 
manner : 

Train Accidents : Accident resulting from the operation and movement 
of trains; example of these are collisions and derailments. 

Train-service Accidents : Accidents including those related to employees 
engaged in coupling and uncoupling locomotives, cars, air hose, steam hose 
and safety chains, employees operating locomotives, handbrakes and switches, 
accidents at highway grade crossings, and casualties involving people who 
are struck or run over by locomotives or rail cars. 

Non-train Accidents : Accidents including those not caused directly 
by the movement of trains such as occurrences in the servicing and repairing 
equipment, roadbed and track, accidents at bridges and tunnels, and accidents 
related to the operation of roadway vehicles. 

The following statistics compiled by the Department of Transportation 
illustrate that the largest number of accidents occuring during 1972 
fell into the category of "train-service" accidents, those most likely 
to involve persons not working for the railroad and which could be classified 
as general local public. Of the different subcategories in the "train-service" 
category, mishaps at grade-crossings accounted for the largest number of 
fatalities . 



470 



Accident Type 


Number Killed 


Number Injured 


Total Accidents 


1,945 


17,930 


Train 


171 


777 


Train-service 


1,704 


11,507 


Grade crossing 


1,165 


3,172 


ULner classes 




O , J J J 


Non— train 


70 


5 ,646 


Number killed/injured per 






million train-miles */ 


3.8 


35 









*/ Total train-miles for 1972 was 512 millions in transportation 
service. Class I railroads. 



Considering that most of the towns through which unit trains will be 
passing are not equiped with overpasses, the prospect of significant in- 
creases in the number of these trains coupled with the statistics on the 
number of people involved in grade-crossing mishaps amounts to a legitimate 
concern on the part of local residents. 

One of the cities already affected by unit-train traffic is Fort Collins, 
Colorado. Fort Collins is located on one of the rail lines over which Burlington 
Northern unit trains will be traveling from Gilette, Wyoming to points along 
the Colorado Front Range. Residents of Fort Collins, in an article in the 
May 21, 1976 issue of The Word , the local daily newspaper, expressed their 
concerns over the increasing number of coal trains passing through the town. 
Most of the concerns could be classified as impediments that the coal trains 



471 

would present to the migration of vehicular and pedestrian traffic from 
one side of the city to the other. In addition, many of the merchants were 
concerned that increases in rail traffic (blowing coal dust, increased 
vibrations, etc.) would adversely affect property values in the commercial 
districts of the city, which are located adjacent to the rail line. 
Proposals to alleviate their particular problem included routing the train 
traffic around the city on an alternate line. A subsequent article (Energy 
Daily, November 2, 1976, p. 2) dealing with the Fort Collins problem ex- 
plained that the Burlington Northern Railroad had tentatively agreed to 
route its trains around Fort Collins and other Front Range communities. 
The article, however, did not address similar problems and solutions that 
will be confronted by smaller communities along Burlington Northern's other 
main lines out of the Northern Great Plains coal development area. While 
the projected tonnage through Fort Collins would ultimately amount to 
about 500,000 tons of coal annually, the total tonnage of coal being moved 
by unit trains out of the Eastern Powder River Basin during 1974 amounted 
to over 22 million tons. Much of this coal moved over theB/N southern 
route to points such as St. Louis, Mo., and over the northern route to 
Minneapolis, Chicago, Illinois, as well as to Duluth/Superior , Minnesota 
to be shipped via the Great Lakes to utilities like Detroit Edison. This 
22 million ton figure represents a 630% increase since 1970 in the coal 
being transported out of Wyoming and Montana on unit trains. Consequently, 
many of the towns and communities along these routes anticipate increasing 
disruption by the passage of the coal trains. 



472 

Alternatives to the present course of transportation . 

Many of the advantages derived from train-unit shipping are the result 
of the inflexibility of the transportation system. In order to lower 
the cost of shipping coal, the trains must be kept moving almost constantly, 
from a specified shipping point to another specified and fixed receiving 
facility. These limitations can likewise be applied to the coal-slurry 
pipeline (see section 3.4.6. of this volume) with the exceptions that slurry 
pipelines do not make the noise than unit-trains do, are not responsible 
for emissions that diesel engines are, and do not subject local residents 
to the hazards of unit-trains that have already been discussed. Therefore, 
many persons located in the areas affected by unit-train traffic perceive 
the coal-slurry pipeline as an attractive alternative to the unit-train 
mode of coal transportation. In order for this mode to be considered a 
viable alternative, however, Congress will have to resolve the question 
of eminent domain that has stymied the construction of slurry-pipelines 
across existing rail lines (see section 3.4.6.) in the Western United 
States. 

Other possible alternatives to the problem include the construction 
of bridges and overpasses in order that existing rail lines can be used 
with a minimum of disruption to local vehicular and pedestrian traffic. 
This is quite expensive, would have the effect of concentrating road 
traffic on the over-passed streets and would reduce the accessibility 
and value of property along those streets along the up-ramps and down- 
ramps of the overpasses. 

As in the case of Fort Collins, cooperative efforts could be made 
between the railroads and the communities to route the trains around 



473 

more congested areas. This lengthens the overall distance of the run, 
increasing movement costs and mine to delivery turnaround time, as well 
as perhaps impacting on other communities now avoiding this problem. 
Perhaps the railroads could try to plan the shipments of coal in order 
that the unit-trains traverse congested areas at night. 

In some instances, it may be cheaper for the railroads to provide 
assistance to the communities to purchase additional emergency fire and 
rescue equipment that can be located on both sides of the tracks, to 
avoid the possible isolation of sections of towns in the event that 
emergencies occur during the time that unit-trains may be passing through, 
than to route trains over much longer alternate routes that avoid towns 
altogether or to build overpasses. This may mitigate some of the 
resident's safety problems, but does not help with the general inconvenience. 
In the absence of any help from the railroads, assistance from the Federal 
Government may be necessary to enable the local communities to duplicate 
emergency service to all parts of the town that may be isolated or to aid 
the railroads in building track completely around the towns altogether. If 
it is necessary for these communities to be inconvenienced in order 
for adequate supplies of coal to be brought East, then perhaps it is 
a fair tradeoff for the revenues generated by the exporting of coal to 
alleviate as many as these inconveniences as possible. 

There are no inexpensive ways to reduce the impacts of increased 
train traffics through such small towns, other than perhaps by publishing 
and adhering closely to a schedule of times when trains will be crossing 
on the intersections as that people can better plan their activities to 



474 

avoid the crossings at those times. The costs of bypassing such communities, 
building numerous bridges and' over or underpasses, or duplicating emergency 
facilities, would pose, if born along the entire route, a major and currently 
unaccounted factor in the economics of such coal movement. This factor 
may play a critical role in the competition between unit trains and 
other forms of coal movement. 



475 

3.4.4. Long-term Contracts or Rates for Railroads Hauling Coal * / 

One idea that has been suggested to make railroads more competitive 
with potential coal slurry pipelines is that railroads be permitted to make 
binding long-term transportation contracts with shippers of coal. Currently 
not allowed by the ICC, and possibly illegal under the statutes governing 
railroads, such rates might permit savings to the railroad from greater 
certainty of traffic and administrative ease that could be passed along 
in rate reductions. Slurry pipelines must have long-term contracts, and 
fairness between the modes may suggest that railroads be permitted them too. 
The problems that are raised are equity among shippers, among railroads 
and among modes, as well as the changes that would be necessary in the 
regulatory or statutory framework currently in place. Finally, the rail- 
roads may not be interested (as discussed below), at least until slurry 
pipeline competition is imminent. 

3.4.4.1. Background . If coal production and consumption rise over the 
next few years as predicted in the National Energy Plan, coal transportation 
will have to increase accordingly. Railroads are the current leaders in 
coal movement, and essentially the sole carrier for long-distance overland 
movements. Unit train service, composed of entire trains of cars which re- 
main coupled and travel only between the mine and the user and back, has 
greatly improved the economics of coal movement by rail in recent years. 
In addition, 100 ton-hopper-cars have begun to replace older 55-ton cars, 
increasing train capacity. Finally, new methods of switching and train 



V Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 



476 

control have made it possible to put more traffic on a given line. These 
efficiencies have helped to make long distance coal movement relatively 
less expensive over the past few years. 

Nonetheless, some coal interests have proposed slurry pipelines as a new 
means of moving coal overland, which they claim would be even less expensive 
than unit trains for such high volume continuing movements. Although 
some studies dispute this contention, other studies do see possible savings 
over certain routes. The railroads, fearful of losing profitable and 
large scale traffic, are opposing legislative grants of the power of eminent 
domain to coal slurry pipelines. (See 3.4.6.) 

Another option that has been suggested, however, is to put the rail- 
roads into a more competitive stance against the pipelines by amending their 
regulatory treatment in ways which would allow them to lower their rates 
to shippers. If the railroads were able to offer lower rates than slurry 
pipelines for the same service, it is unlikely that those slurry pipelines 
would be built, not because of legislative and other institutional constraints, 
but because of market competition. 

There are some who suggest that the railroads already have the flex- 
ibility to do this. They suggest that rates for unit train movements which are 
fully legal — covering variable costs and making an adequate contribution 
to fixed costs — could today undercut proposed slurry pipeline costs, but 
would not be put into effect until slurry pipeline competition is an immediate 
threat. These people suggest that the railroad opposition to slurry pro- 
posals is derived more from a fear of the loss of monopoly rates than 

1/ 

from an inability to haul coal at competitively low rates. 

\l Dr. Gordon Parish, ICC Bureau of Economics, brougt this view point to my 
attention. 



477 

Others argue that coal rates are today lower than they will have to 
be to make possible the necessary investment that will be required for 
enlarged coal movements in the future. (See 3.4.2.) If this is true, it 
would not be possible for rail rates to be lowered to meet slurry pipeline 
competition consistent with maintaining service. In this case, a valid 
public concern over the continued viability of the railroads give weight 
to the case against slurry pipelines. If current rates are monopoly rates, 
and railroads are in such awful financial shape, what would competitive 
lower rates do? 

Whether or not railraods could afford to reduce coal rates under 
the current regulatory framework to compete with slurry pipelines, there 
have been suggestions that changes in the regulatory format would enable 
railroads to do so. 

One change that has been mentioned in several places, but apparently 
not yet studied at length, is a change to permit railroads to make long- 
term contracts with shippers for movement of coal. Standard rate agreements 
may extend for a maximum of one year. The recent Railroad Revitalization 
and Regulatory Reform Act (4R Act) included a provision allowing rates to 
be established for a five year period without change where an investment 
in transportation equipment of more than one million dollars is made. 
Yet even this longer period does not compare with the terms of contracts 
required for coal slurry pipelines, which range from 20 to 30 years. 

Unit-train rates and other rates which are tied to volume of traffic 
were once similarly denied by the Interstate Commerce Commission. Coin- 
cidentally, it was the loss of coal movement to a coal slurry pipeline 



478 

in Ohio which prompted the first unit trains and volume discount rates. 
The coal slurry pipeline was driven from business by the rate cut. 
Volume discount rates for unit trains are now widely accepted, although 
they must still be granted outside the normal structure. There have been 
few problems with such agreements, which are, however, more in the nature 
of a continuing understanding between the railroad and the shipper in 
regard to the stability of the rates over time, than they are officially 
ICC approved long-term contracts. The fact that shippers often own or 
lease the coal cars used in such unit trains increases the stability of 
such arrangements. 

3.4.4.2. Long Term Contracts Possibilities. Although the lower 
costs that result from trainload volumes or unit train efficiencies can 
now be reflected in transport rates, the ICC has not yet allowed lower costs 
resulting from certainty of volume over time to be reflected in the rates 
approved. A coal slurry pipeline must have a throughput agreement for the 
live of the facility in order to be built, because it has essentially no 
volumetric flexibility, other purposes, or scrap value. If railroads were 
also permitted to contract with shippers for volumes of traffic over a long 
period, they would have the benefit of a certain revenue on which they and 
their potential investors or creditors could count. Their cost of financing 
reflects the future traffic uncertainty they cannot now avoid, and should 
decline with greater assurance that their facilities would be utilized. 
The rate of utilization of their cars would improve from the current low 
percentage toward the theoretical maximum of 50% loaded utilization. In 



479 

addition, there would be obvious savings in shipment record keeping, billing, 
switching time and requirements, and traffic planning costs from knowing 
in advance and with certainty of the traffic requirements. A contractual 
obligation to pay for a given level of shipment regardless of whether or not 
the coal was tendered could increase the certainty of revenues even more, 
again reassuring railroad investors and lowering the return they would require. 

These savings would presumably be sufficient to allow lower rates 
to shippers who were willing to undertake the contractual obligations. 
The shippers would benefit by having both the lower rate and the certain- 
ty of transport for his coal. 

Both the railroad and the shipper would be "locking themselves in" 
over the term of the contract. The railroad might miscalculate its ad- 
vancing costs of inflation, labor, and maintenance, or might fail to pro- 
vide for them adequately by means of contractual clauses which indexed 
the contract rate to such variables. The railroad could then end up carrying 
coal at a loss. The shipper, on the other hand, would preclude his own 
use of other transportation, such as slurry pipelines, which might be 
cheaper yet, or might be unable to participate in the benefits of general 
rate reductions of the railroad caused by improved technology or other 
factors . 

Hence, for both parties to such a contract, there would be potential 
costs to weigh against the clear benefits of having such certainty. Some 
railroad spokesmen have suggested that electric utility companies, the most 
likely large scale coal customers, would be uninterested in a reduced 



480 

2/ 

transport rate if it meant a long-term commitment. Others have sug- 

gested that utilities would be glad to arrange for coal transportation that 
would supply their generators for terms as long as the useful life of 
those generators, gaining greater certainty of supply to help reduce 
their own capital costs, and requiring regulatory review only once 
instead of numerous times. Certainly it is hard to understand why coal 
burning utilities interested in participating in slurry pipelines, with 
their necessary twenty to thirty year contracts, would be less interested 

3/ 

in long term rail agreements if they were available at a competitive cost. 
Still others suggest that the railroads themselves would oppose long- 
term contract making authority at least until slurry pipeline construction 
was legal and imminent, because they would be pressured to make 

such contracts and reduce rates under current monopoly levels without 

4/ 

gaining much in traffic as a result. 

3.4.4.3. Effects on Other Shippers, Other Railroads, and Other Modes 
While long-term contractual authority might thus benefit both railroads and 
shippers, other parties may be affected. 

One of the serious concerns which has kept such contracts from being 
adopted or even seriously proposed in the past is the possible effects on 
other shippers than the one who had the contract. A main purpose of railroad 
and common carrier regulation is to prevent discrimination among shippers. 

Ij Conversation with Allen Boyce, Burlington-Northern RR. 

Zj For a discussion of the economic factors of such contracts in a 

regulatory situation, see V.P. Goldberg, "Regulation and Administered 
Contracts," Bell Journal of Economics . Autumn, 1976, pp. 426-448. 

4/ See footnote 1. 



481 

Of course, if the railroad offered the same rate to any shipper willing to 
commit itself to a given volume of deliveries over an equally long term, 
or scaled the rates to volume, term of contract, and distance of shipment 
using a standardized approach that any shipper could employ, any unfairness 
among shippers would be reduced. If such rates were focussed exclusively 
on coal, which is largely delivered to steam power plants of electric 
utilities serving defined service areas as regulated natural monopolies, 
the potential for injury by affecting competition among shippers is minimal 

— the electric utilities do not compete with each other. It is the shippers 
of other commodities and finished goods who are most worried about slight 
differences in their transportation rates. In addition, coal as a commodity 
is more susceptible to long term contracting in all phases than most goods 

— it supplies a continuing steady demand, not the wide swings of a consumer 
product market. Its supply is not as seasonal or variable on a year-to-year 
basis as agricultural products or other bulk commodities. Trainload quantities 
are not too large for consumers to deal with, as would be trainload quantities 
of almost any other product. Allowing long-term rates for coal movement 
would not necessarily require the same allowance for all other materials 
shipped by rail. 

The effect on other railroads of permitting such rates must also be 
addressed. The threat to competition among railroads is that such long 
term contracts reduce competition among railroads by preventing the shipper 
from switching his traffic to another line for the term of the contract, 
even if the other line is later able to undercut the contract rates. It 



24-786 O - 78 - 32 



482 

is possible that one railroad could use contract rates to lock up the traffic 
in a given area to which another railroad would desire to exend or improve 
service. It might be possible to deal with such inter-railroad questions 
through railroad rate bureaus. If the railroads of a given area could agree 
among themselves what contract rates and terms would be acceptable, 
the harmful effects of such rates on those railroads can be presumed to 
have been taken into account. On the other hand, such mutual agreement 
would be very difficult to achieve if one carrier felt itself incapable 
of participating in the rate, possibly preventing others from utilizing 
contract rates which might be beneficial not only to themselves, but to 
the railroads generally and to the general public interest. 

In regard to the effects of such contract rates on other modes, they 
would obviously work to the disadvantage of coal slurry pipelines. They 
would also enable railroads to compete better with water carriers, who now 
dominate in traffic along river corridors. Few water carriers are operated 
as common carriers, and privately owned barges are common. Many coal-hauling 
agreements by barge are multi-year in nature. Railroads would thus not be 
gaining any advantage that barge traffic could not or does not already have. 
Trucks are not now feasible nor likely to be in the future for long haul 
large volume coal movements. They, too, moreover, can currently engage in 
long movements because they are often privately owned. Regulated interstate 
truckers carry essentially no coal. On balance, it does not appear that 
long-term contract rate capability for coal movement would unfairly jeo- 
pardize other modes of coal transportation. 



483 

3.4.4.4. Compatibility with Statute and Regulation . Congress could 
obviously amend the law to make it clear that long-term contractual 
agreements for coal hauling can be signed between railroads and shippers, 
and could condition the applicability of such a provision as seen fit. 
It might be limited to areas in which coal slurry pipelines have been 
proposed, or to agreements to which no other railroad objects. More- 
over, if questions of committee jurisdiction were not an obstacle, such 
a provision might be coordinated with the ongoing consideration of eminent 
domain for slurry pipeline rights-of-way. 

The ICC, however, may now have authority to permit such arrangements 
if it so chooses. Even prior to the 4 R Act's provision permitting five-year 
rate freezes where investments of more than one million dollars are made, 
the ICC approved and the courts accepted four incentive rates which may be 
analoguous. Three of these involved coal movements, and the other concerned 
residual fuel oil. 

In one case, a rate reduction of 35c per ton of coal was needed to 
make continued rail shipment of coal preferable to high-voltage electric 
transmission, locating a new generation plant in the consuming area instead 
of at the mine mouth. The ICC permitted the reduction if a minimum annual 

volume of 1.5 million tons per year was carried, assessed each month for the 

5/ 

previous twelve months to keep the rate in effect. In a second case, 

coal rates to New York Harbor were reduced 50c per ton after the total 
annual shipments exceeded a specified minimum. The purpose of the reduction 



_5/ Coal from Kentucky, Virginia, and West Virginia to Virginia 208 ICC 99 
(1959) . 



484 

was again to meet competition, but not from another mode of energy movement - 

instead, it was to keep residual fuel oil from replacing coal under boilers 
6/ 

in New York. A third approved annual volume and loyalty incentive rate 

was adopted to prevent the construction of a coal slurry pipeline to Detroit. 
Reductions of 37.5c per ton were granted for shipments up to, and 50c per 
ton for shipments in excess of, a steadily escalating volume of coal, rising 
from 6 million tons in 1962 to 8.7 million in 1971. No opposition was 
raised to this rate, and the 10 year period for which it was to apply is 
also unusual. 

These three cases are fully described in a book by Robert Lundy, now 
with the ICC, which focuses on loyalty-incentive rates, wherein a given 
shipper achieves a reduction by pledging a certain percentage of his 
traffic to a given railroad, but the book also cites numerous annual volume 
rates. 

The rates allowed under these cases differ from long-term contract rates 
which would provide certainty to the railroad of the traffic and/or revenue, 
because the shippers were not responsible for the railroad's lost revenues 
if they failed to meet the minimum; they simply lost or had to pay back 
the rate savings the volume discount had made possible. Hence these cases 
would appear to be precedential for discounted rates based on annual volumes, 
but not necessarily for long-term traffic commitments on a take-or-pay basis. 

6/ Coal to New York Harbor Area, 311 ICC 355 (I960). 

l_l Bituminous Steam Coal, Eastern District of Detroit, etc. Ohio Coal 
Rate Tariff No. 14-C, ICC No. 72 (effective, June 20, 1982). 

Lundy, Robert F. "The Economics of Loyalty-Incentive Rates in the Rail- 
road Industry of the United States." Washington State University Press. 
Pullman, Washington, 1963. 



485 

It may be that such volume discounts, perhaps combined with unit train 
service, would be attractive enough in their own right to provide es- 
sentially the same certainty of traffic to the railroad and its investors 
as a written guarantee. In addition, the risk to the railroad of a long 
term commitment at less than adequate rates is similarly reduced. 
Perhaps some of the components of unit train agreements which add to 
their permanence, such as shipper ownership of equipment, can be added 
to annual volume discount arrangements to increase the certainty of con- 
tinuing traffic. Or perhaps unwritten gentlemen's agreements between 
the railroads and the shippers would suffice to assure the long-term 
continuation of the traffic. 

If, however, only a signed contractual commitment to ship a given 
volume per year is capable of achieving savings sufficient to allow rate 
reductions of the size needed to compete with slurry pipelines, then an 
apparently unprecedented ruling from the ICC would be required. The ad- 
vantages of such an arrangement to the railroad would be carefully weighed 
by the ICC against both the statutory requirements of non-discriminatory 
service by a common carrier and the national transportation policy of fosteri 
the potential of each mode of transport. 

Finally, it is possible that the ICC would feel that the "five-year, one 

million dollar investment" provision of the 4R Act would obviate the need 

for such contract approval. The rates which have so far been set under 

9/ 

that provision are not especially low rates. It may be that unless slurry 
pipeline construction was both legally possible and imminent, the railroads 



9/ See footnote I. 



486 

would disdain to offer long-term rates at any savings. When slurry pipelines 
are both legal and imminent, however, it may be too late for the railroads 
to employ such rates if they still require statutory or ICC action to 
make them possible. 



487 

3.4.5. Coal Transportation Impacts of Lock and Dam 26 * / 

During the 94th Congress, the issue of whether or not the Locks and 
Dam # 26 on the Mississippi River near Alton, Illinois received consider- 
able attention. Concern on the part of water carriers was not limited to 
coal-hauling alone, but included other bulk commodities such as grain 
produced in the Midwest and moved downstream to export facilities at 
such locations as New Orleans. 

According to the Army Corps of Engineers, the locks and dam which 
have been in use since 1938 and are outdated should be replaced with new 
equipment for a number of reasons including the following: 

(1) The structure is founded on wood friction piles driven into 
sand and has a history of settling, deflection, and under- 
seepage. 

(2) There has been a loss of foundation materials which has generally 
weakened the structure. 

(3) Because the locks and dam are relatively shallow, there has been 
considerable scouring both upstream and downstream of the instal- 
lation in the channel of the river. 

(4) Increasing difficulty in maintaining and operating the lock and 
considerable cost to the Corps. 

(5) Increased delays for barge tows which have to negotiate the locks, 
and have presented serious questions about the capability of 

the locks to accomodate increasing river traffic. 

In a prepared statement at hearings in 1976 before the Subcommittee 
on Water Resources of the Committee on Public Works, 94th Congress, second 
session. Corps representatives offered some alternative solutions to the 
problem: 



7 Prepared by Duane A. Thompson, Analyst, Environment and Natural 
Resources Policy Division. 



488 

(1) Improvement of operational procedures at the existing facility; 

(2) Rehabilitation of existing facility with and without improvements; 

(3) Complete replacement upstream of Alton, Illinois; 

(4) Complete replacement about 2 miles downstrean of present site; 

(5) Complete replacement at present L & D 27 site; 

(6) Complete replacement about 30 miles dowstream of present site 
(downstream of St. Louis). 

Basically, the controversy over the replacement of the locks and dam 

centers on whether or not it is the ulterior motive of the Corps and 

the water carriers to enhance their haulage capacity by deepening Locks 

and Dam # 26, thereby setting the stage for the subsequent deepening of 

the entire channel in the upper Mississippi River, all at the expense 

of the railroads that service the same shippers. The upper Mississippi 

channel, currently dredged to a 9 foot channel, would have be 12 feet deep 

for its entire length in order to accommodate larger vessels. The Corps 

say "no" — that the locks should be deepened just in order to maintain 

the status quo, and that there are no plans for the dredging of a deeper 

channel north of the locks. Current shipping installations on the upper 

River and the tonnages of commodities that would be moved in the foreseeable 

future would not warrant dredging the channel in order to accommodate deeper 

tows. The railroads, on the other hand, perceive the reconstruction of 

Locks and Dam # 26 as another move on the part of the Federal Government 

to subsidize the water carriers at the expense of the railroads. Many 

waterways operators believe that the action or inaction on the part of 

the Government to resolve the issue is merely an effort on the part of 



489 

the competing carriers to extract a waterway-users charge from the 
barge lines in trade for the reconstruction of the locks. 

It is not within the scope of this work to suggest a resolution to 
the problem of whether or not the locks and dams should be reconstructed 
or to determine if they should be enlarged. 

The logic which is being applied by the Corps of Engineers appears 
to be valid, however, in saying that even if there is to be no change in 
river traffic levels or character, something should be done about the 
current deteriorating lock. It is pertinent, however, to offer some in- 
sight as to how coal traffic up and down the River could be affected 
by enlargement of the existing structure. 

Basically, the current patterns of coal traffic on the inland water 
system in the United States are outlined in Volume I of this study and 
on the map (# 4) that accompanied Volume I. According to BOM, IC # 8706, 
the coal being transported by the barge system is generally destined for 
consumption points along the same rivers where it has originated .( See 
Figure I). The only notable exception to the pattern is the case of coal 
originating along the upper Mississippi River and going to the Illinois 
River. The report does not elaborate on the natural origin of the coal, 
whether or not it actually crosses the Locks and Dam # 26, but assuming 
that it does, the total tonnage of coal is still a relatively small amount. 
A chart based on the information in volume I of this study illustrating this 
flow of coal through the locks has been provided. If the testimony 
of the Corps is accurate, given the small amount of coal traffic and the 
fact that the channel of the actual River will not accommodate deeper- 
draft barges even though the locks themselves are deepened, the probable 



490 



Below Locks and Dam #26 



FLOW OF COAL THROUGH LOCKS AND DAM #26 
ON THE UPPER MISSISSIPPI RIVER 



Calendar Year 1974 
Coal Shipments 
(short tons) 



Above Locks and Dam #26 



Miss. River: mouth of 

the Mo. River to the 
mouth of the Ohio River y- 



Ohio River: Engineer 

District, Louisville 



Miss. River: 

Minneapolis, Minn, to 
mouth of Mo. River 



Ohio River, Engineer 

District, Huntington 



Ohio River, Engineer 

District, Pittsburgh 



>- 



>- 



Tennesseee River, Tenn. , 

Oklahoma, and Kentucky !>-- 



The Green and Barren 
River, Kentucky 



Kanawka River, West Va. 

Monongahela River, 

Pa. and West Va. 



7r- 



i— 



2,221,345 
1,117,495 
992.327 
132,628 
41 ,082 
48,876 

181,097 
71,915 
5,609 
17,008 



4,557 

8,788 

30,145 
7,595 
115,262 

1 ,556 
6,503 

133,891 
24,678 
17,454 

163,434 
16,815 

587,312 
126,095 
32,797 
5,787 

22,237 
7,042 

5,787 
1,351 



-> 

-9 

-> 



--> 
-> 

-> 



-1 



Miss. River: Minneapolis, Minn. 

to the mouth of Mo. River 
Illinois River, Illinois 
St. Croix River, Wise, and Minn. 
Minnesota River, Minn. 
Lake Michigan 
Port of Chicago 

Miss. River: Minneapolis, Minn. 

to the mouth of Mo. River 
Illinois River, Illinois 
Lake Michigan 
Port of Chigaco 

Miss. River: New Orleans to 

Mouth of Passes 
Miss. River: Baton Rouge, La. 

to mouth of Miss. River 
Miss. River: Minneapolis, Minn. 

to mouth of Mo. River 
Illinois River, Illinois 
Port of Chicago 

Miss. River: Minneapolis, Minn. 

to mouth of Mo. River 
St. Croix River, Wise, and Minn. 
Miss. River: Minneapolis, Minn. 

to mouth of Mo. River 
Illinois River, Illinois 
Black River, Wise. 
Lake Michigan 
Port of Chicago, Illinois 
Miss. River: Minneapolis, Minn. 

to mouth of Mo. River 
Illinois River, Illinois 
St. Croix River, Wise, and Minn. 
Minnesota River, Minn. 
Miss. River: Minneapolis, Minn. 

to mouth of Mo. River 
Port of Chicago, Illinois 
Miss. River: Minneapolis, Minn. 

to mouth of Mo. River 
Lake Michigan 



491 



Below Locks and Dam #26 




Above Locks and Dam #26 



Calendar Year 1974 
Coal Shipments 
(short tons) 




Allegheny River, Pa. 



> 



13,762 



■T> Lake Michigan 



Miss. River: 

Baton Rouge, La., to 
but not including 

New Orleans, La. V 1,550 -i^ Illinois River, Illino 

Miss. River: 

mouth of the Ohio River 
to but not including 

Baton Rouge, La. \- 1,396 ' 

Miss. River: 

New Orleans, La. to 

the Mouth of Passes 1,588 < Minnesota River, Minn. 

Miss. River: 

mouth of the Miss. 
River to north of 



the Ohio River 



1 ,412 




Note: The above diagram assumes that no coal shipments were either made or received 
in the thirty-mile section of the Mississippi River between the mouth of the 
Missouri River and the Locks and Dam #26. 



492 

effect on the barge transportation of coal that would otherwise go by 
railroad will be minimal. 

For electric utilities that will be built in the future in the up- 
per Mississippi River region, the coal necessary to sustain these opera- 
tions could be shipped overland from the Northern Great Plains on the 
Burlington Northern or other railroads. It has been mentioned that some 
companies within the coal industry are planning to build coal transfer 
and shipping facilities at St. Louis for the purpose of forwarding North- 
ern Great Plains coal, received from Burlington and Northern unit trains, 
to barges plying the Mississippi River. If the transfer facilities are 
constructed, however, coal coming to St. Louis very likely would not have 
to be sent through the Locks and Dam # 26. Points as far north as Bur- 
lington, Iowa could be served entirely by the Burlington and Northern 
Railroad by using their southern route structure through Nebraska and 
points farther to the north could be served by the Railroad's northern 
route structure which comes through Minnesota. The only points along the 
upper Mississippi River which could not be served directly by the Burlington 
Northern are along the River from Savanna, Illinois, to Burlington, Iowa, 
a distance of approximately 100 miles. 

Those in the industry thoroughly familiar with the issue of Locks 
and Dam # 26 have indicated that the decision of whether or not to re- 
place the existing structure with new and enlarged one is tied to the 
decision of the Federal Government of whether or not to impose some 
kind of a waterway user's tax on the barge lines. Such a users tax 
would require waterways operators to carry part of the cost of maintaining 



493 



and improving the river system they utilize and would bring their costs 
more in line with those of the railroads. Such a move on the part of 
the Government would change the competition between the two modes of freight 
transportation by eliminating what the railroads see as an unfair advantage 
in favor of the waterways carriers. The waterways operators, however, 
point out land grants and other forms of Federal aid to the railroads, 
protective ICC regulation which supports railroad rates at remunerative 
levels, and similar Federal aid to highway and air modes of transportation 
(See 3.1.9.). 

Even with a user's charge, from the standpoint of coal transportation, 

however, it is questionable whether or not the deepening of the channel north 

of Cairo, Illinois, could be justified on a cost-benfit basis. According 

to a recent study on coal transportation prepared for the Bureau of Mines: 

To make full use of the river, particularly with reference to coal 
shipments from the northern great plains, locks 1-13 would also 
have to be enlarged. This would allow major coal access to the 
river as far north as Minneapolis-St . Paul. The cost for the ad- 
dition, based on the above, is another $1.3 billion or $3.1 billion 
for the upper Mississippi [when added to the Locks and Dam #26 's 
costs]. Even if amortized over 50 years, if the annual charges 
had to be paid by users, it is worth a study to see if the costs 
would allow users to remain competitive with other modes of 
transportation. _l/ 

The Bureau of Mines appears to suggest that the users of such water- 
ways could not successfully pass on the costs of such improvements if re- 
quired to bear them. The question is thus whether the national interest 



l_/ Comparative Coal Transportation Costs: An Economic and Engineering 
Analysis of Truck, Belt, Rail, Barge and Coal Slurry and Pneumatic 
Pipelines, Volume 4, Barge Transportation, prepared for the United 
States Department of the Interior, Bureau of Mines and the Federal 
Energy Administration by the Center for Advanced Computation, Univer- 
sity of Illinois at Urbana Champaign Urbana, Illinois, August, 1977, 
pp. 4-24. 



494 

would be well served to spend such funds on a project which would not be 
able to repay them, should the Federal Government consciously subsidize 
waterways on the Northern Mississippi, at the expense of other modes of 
transport, and at the expense of an outright loss to the U.S. Treasury. 
The likely answer, at least considering the previous desires of the cur- 
rent administration to reduce outlays for waterways projects which are no 
cost effective, is no. But if the Federal Government does not undertake 
these improvements, it is clear that western coal traffic on the upper 
Mississippi will continue to be quite limited, and that the replacement 
of Lock and Dam #26, without further actions, would not have a marked 
effect on coal movement on the rivers. 



495 

3.4.6. Coal Slurry Pipelines */ 

Plans have been announced by several companies for construction of coal 
slurry pipelines to transport coal from mine sites to power plants and 
other consumers. These projects have contemplated development of the 
substantial reserves of coal in the Western United States, but the coal 
slurry technology — the pumping of finely ground coal suspended in water 
through pipelines — could conceivably become a means of coal transportation 
in any region. Legislation has been introduced to grant the requisite 
rights-of-way across Federal lands, and also to establish the power of 
eminent domain to obtain rights-of-way across private lands. The granting 
of eminent domain was sought because numerous railroad lines and other 
private holdings would have to be crossed. As direct competitors in 
transporting coal, the railroads have expressed strong opposition to the 
project and to the granting of eminent domain powers. 

A related issue involves the significant interbasin transfers of 
water that would be required to operate such pipelines. One major pipeline 
proposed would require 15,000 to 20,000 acre feet of water per year. Since 
all of the proposed pipelines are in arid areas of the West, the large 
water requirements continue to be the cause of considerable concern. Pipe- 
line legislation in the 95th Congress would not affect existing water 
rights nor allow eminent domain as it pertains to water. The affected 
States, rather than the Federal Government, will decide on the water issue. 

3.4.6. 1. Background . The technical and economic feasibility of coal 
slurry pipelines has been demonstrated in two earlier projects. The first 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 



496 

ran 108 miles from Cadiz, in southeastern Ohio, to Eastlake, in suburban 
Cleveland. This line, built in 1957, operated for six years and was then 
shut down because of substantially reduced railroad freight rates. Pipeline 
advocates credit the Ohio pipeline with stimulating the development of 
unit trains. The lO-inch diameter pipe had a capacity of 1.3 million tons 
of coal per year. 

A second pipeline, currently in operation, runs 273 miles, from the 
Black Mesa mine on Navajo land in northeastern Arizona, to the Mojave Power 
Plant in extreme southern Nevada. The 18-inch diameter pipe has a capacity 
of 4.8 million tons of coal per year. 

In 1973, Energy Transportation Systems Inc. (ETSI) announced plans for 
a 1,030-mile coal slurry pipeline to run from the Gillette, Wyo. , area to 
the Pine Bluff, Ark., area. ETSI, an affiliate of Bechtel Inc., Lehman Bros. 
Kansas-Nebraska Natural Gas Company and Western Energy Transport Company, 
is based in San Francisco, California. 

The proposed pipeline would have a 38-inch diameter with a capacity of 
approximately 25 millions tons of coal per year. Arkansas Power and Light 
Co., a subsidiary of Middle South Utilities Inc., is the principal planned 
purchaser of the coal. 

Four smaller-capacity coal slurry pipelines are also under consideration 
in other regions: (I) a 1,100-mile, 7-million-tons-per-year line from north- 
west Colorado to the Houston, Texas, area; (2) a 180-mile lO-million- 
tons-per- year line from Utah to Nevada; (3) a 180-mile, 4-million-tons-per- 
year line from New Mexico to Arizona; and (4) a pipeline from Wyoming to 



497 

Oregon. Recently, plans were also announced for a 1,260-inilej 30-million- 
tons-per-year line from Montana to Texas. The Slurry Transport Association, 
organized in Washington, D.C., represents this young industry. 

The technology of slurry pipelines consists of grinding the coal or 
other material to a powder of sufficiently fine consistency to mix well with 
water, mixing the powder in approximately equal proportions with water, and 
pumping it through the pipeline. On the longer pipelines, supplemental pump- 
ing plants are generally required at various points. At the receiving end, 
after the coal is separated from the water, it can be burned directly for 
thermal electric generation or transferred to other transportation modes. 
When clarified, the water can be used for cooling or other purposes. 

Large deposits of coal are located within the Upper Missouri River. 
Basin. Previously considered marginal because of their low grade and 
distance from markets, these deposits now offer good prospects for exploita- 
tion because they are easily strippable and are generally considered to 
be low in sulfur. This is an arid region, however, with relatively 
limited water supplies. Agricultural and other interests in the region 
fear that their water supplies will be preempted by coal development. The 
Yellowstone sub-basin from which the ETSI pipeline would originate is the 
focus of both coal development proposals and concern over the use of 
limited water supplies. An aqueduct proposal and industrial water 
marketing contracts to serve coal development have been the subject of 
considerable controversy, and the contracts are the subject of litigation. 
A coal slurry pipeline requires considerably less water per ton of coal 
than on-site processes, such as coal gasification or thermal electric 
generation. Concern has been expressed by local interests about exporting 

24-186 O - 78 - 33 



498 

the natural resources in this manner rather than fostering regional 
development at the source.. Railroad movement of coal requires very 
little water, but the major railroads have also applied for water 
rights for coal development purposes. 

Most attention to coal slurry pipeline proposals has focussed 
on western coal resources. Eastern coal resources are also vast, 
however, and it is possible that the slurry technology would be 
equally applicable there (see 3.1.16). Possible advantages are 
better water availability, possible spare pipeline capacity, coal 
of higher energy content, and compability with coal washing projects. 
An advantage or disadvantage for eastern pipelines, depending on the 
conditions of right-of-way approval for them, is the relative weakness o 
the eastern railroads with which they might compete. 

3.4.6.2. Eminent Domain . The granting of rights-of-way across 
public lands, which was sought during the past congressional year 
for the ETSI project, would require an extension of the rights-of-way 
provisions for oil and natural gas under the Mineral Lands Leasing 
Act of 1920 (30 use 185). The principal precedent for the granting 
of the power of eminent domain is that granted to natural gas pipelines 
by the 1947 amendment of the Natural Gas Act (15 USC 7l7f (h)). Oil 
pipelines were authorized to use the Federal power of eminent domain 
during World War II under the war powers of the Cole Act. Federal 
Power Commission licensees for hydroelectric projects can also use 
eminent domain. 

In general, the railroads have expressed vigorous opposition to the 
granting of eminent domain power and to coal slurry pipelines. In 1974, 



499 

coal accounted for approximately 25% of the tonnage and 11% of the revenues 
for Class I railroads on a national basis. Slurry pipelines would naturally 
be used for large-volume, point-to-point shipments, removing the potentially 
most profitable rail traffic. Some railroads have suggested that they would 
be able to compete with coal slurry pipelines if they were permitted to 
engage in long-term contracts with guaranteed payments per year whether or 
not the coal was actually moved — the kind of financing coal slurry pipe- 
lines must have. But such contracts are currently limited to five years 
and only then where an investment of $1 million or more is required (See 3.4.4.). 

The primary financial advantage of slurry pipeline transportation 
as opposed to unit train movement is that pipelines are relatively 
inflation-proof: by far the greatest expense is the initial construction, 
a capital investment, with a certain fixed interest rate. Operation 
and maintenance would be relatively minor. Railroads, subject to uncertainties 
in the cost of labor and maintenance, must pass the uncertainty along 
to coal transporters. 

One possible option would be to put coal slurry pipelines under the 
Interstate Commerce Commission, the agency which regulates railroads, with 
instructions to the ICC to balance the advantages of the two mode, in each 
case, the possible competitive problems and injury to other carriers, the 
need for the service, and other factors, and to act on a case-by-case basis in 
granting permission to coal slurry pipelines to operate where beneficial 
in the public interest. This option would have more flexibility than a 
blanket grant of eminent domain, but would put the ICC to a difficult task 
of weighing alternatives and protecting both the public and the carriers. 



500 

A number of States have enacted eminent domain legislation which either 
includes slurry pipelines specifically or is general enough to be construed 
as including slurry pipelines. Oklahoma, Texas, and Louisiana have recent- 
ly added eminent domain statutes. Some State statutes also address the 
water requirements that might be necessary. In some States, eminent 
domain statutes have included State regulations of any such pipeline as 
a common carrier, and a requirement that the public of that State 
benefit from its use -a difficult obstacle in a State intended to 
be merely tranversed. If the railroad itself has only an easement 
over the right-of-way, it may not have a sufficient interest to prevent 
a pipeline from obtaining a right-of-way. Recent cases in State courts 
have upheld a right-a-way for a slurry pipeline project unless the 
railroad owned the land outright. 

Although the western railroads which would be moving coal from the 
Northern Great Plains regions are healthier than most financially, they 
are basing much of their growth on the expected requirements for moving 
coal. They see the kind of movement which would be feasible for slurry 
pipelines as the most desirable of all. They point to their common 
carrier obligations, obligations to support non-remunerative lines, 
and lower overall rates of return than would be earned by slurry pipeline 
companies, as reasons why slurry pipelines would have an unfair advantage 
if permitted. 

3.4.6.3. Water. The proposed ETSI pipeline would use 15,000 
to 20,000 acre-feet per year of groundwater from a large aquifer known 
as the Madison Formation. A 70-mile-long pipeline would be needed 
to transport the water from the well field to the slurry preparation 



501 

facility. The Northern Great Plains Resource Program has postulated 
that there is potential for development of large groundwater supplies 
for industry from the Madison, and that while the water is of sufficient 
quality for industrial use, it would be marginal to unsatisfactory 
for irrigation, or other uses that require good quality water. There 
is considerable disagreement on this conclusion, however. The sodium 
content was considered too high for irrigation, and, except for near 
the Black Hills, the water could not meet public health standards. 
Several Wyoming communities do, however, use the aquifer for municipal 
supply. Also, several South Dakota communities use the groundwater 
from the Madison Formation and are concerned that energy development 
in Wyoming could be detrimental to their water supply. The current 
drought in the Western States is putting additional pressure on available 
water, and will raise additional obstacles to slurry pipelines. A 
U.S. Geological Survey water expert has suggested that the Madison 
formation appears to be able to recharge itself at a rate of about 
100,000 acre per year. 

Suggestions have been made that water for the pipeline could be 
piped back from Arkansas in a parallel pipeline or brought in from a 
third point such as the main stem of the Missouri. Rough cost estimates 
offered during congressional hearings showed that water from planned ground- 
water sources would cost about $400 to $500 per acre foot, or 1.5 cents 
per million Btu ' s worth of coal transported; water supply from the Missouri 
River would roughly double the cost; and recycling water back from Arkansas 
would increase the cost about eight-fold. The South Dakota legislature has 
failed so far to approve a transfer of water from the Missouri River. 



502 

The water allocation issue goes beyond slurry pipeline. No 
market-style allocation is available for this resource despite clear 
market value. Historic rights to water are often treated as property, 
and currently unallocated water may be subject to numerous competing 
demands. The Federal Government would meet fierce resistance from the 
Western States if it attempted to impose a water resources plan, but 
the States may not be able to nationalize the current system by them- 
selves, at least for the purposes of multi-state projects. 

3.4.6.4. Other Factors and Conclusion . Another issue that may 
arise is the question of ownership of slurry pipelines by oil companies, 
which Interior Committee Chairman Udall has indicated he will oppose. 

A major study of the problems and prospects of coal slurry pipelines 
was ordered by the 94th Congress from the Office of Technology Assessment, 
and the report is now in draft form. The OTA study will incorporate separate 
analyses of four facets of the situation: the demand for coal from various 
producing regions; hypothetical rail and pipeline cost estimates and 
market scenarios, the comparative environmental and socio-economic 
impacts of rail versus pipelines, and the legal and regulatory framework 
surrounding the controversy. The House Interior Committee, which 
held hearings on proposed legislation, has decided not to consider 
such a bill until the OTA report is available; i.e., not until the 
second session of the 95th Congress. 

The principal bill before the 95th Congress, H.R. 1609, would amend 
the Mineral Leasing Act of 1920 to grant coal pipelines rights-of-way across 
Federal lands and, where necessary, would have authorized the use of 



503 

eminent domain to obtain rights-of-way across private lands; this authority 
would be contingent upon receipt of a certificate of public convenience 
and necessity from the Department of the Interior. Slurry pipelines 
must be common carriers and multiple uses of rights-of-way are permitted. 
Hearings have been held on H.R. 1609. The Carter Administration has 
indicated its support of eminent domain legislation for slurry pipelines. 
Hearings are likely to begin soon in the Senate on a similar bill. 

Congress is likely to determine the coal slurry issue during 
the remainder of the 95th or 96th Congress, depending on the press 
of other business during 1978. Because of the great emphasis on coal 
use to displace foreign energy and to ease the pressure on natural 
gas supplies, the time is ripe for slurry pipeline planning and construction. 

Two independent issues appear to control the fate of slurry pipelines: 
the availability of water and the ability of the railroads to withstand 
pipeline competition. The first issue appears best left to a resolution on 
a State-by-State basis. Possible water sources appear to be available 
to slurry, pipelines . The Federal Government has no desire for the uproar 
that would follow the preemption of .water rights for slurry pipelines. 
The slurry pipeline companies are apparently satisfied to arrange 
for water supplies without Federal assistance. 

Joint regulation of slurry pipeline and railroads by the ICC, under 
mandate to preserve viable rail systems, may provide adequate insurance 
that the pipelines would not undercut railroad systems. The case has not 
yet been convincingly made that railroads, at least western railroads, 
would be irreparably damaged by a slurry pipeline industry, although they 
would suffer from reduced expectations of the future. 



504 



If these two issues can be resolved, then there would appear to be 
little remaining reason why the slurry pipeline technology could not 
participate in the enlarged coal movement anticipated in the next few decade 
The technology appears to offer economies and benefits which, weighed 
against the cost of its judicious application, would seem worth achieving. 

References 

Battelle Memorial Institute. Proceedings of the International Technical 
Conference on solid liquid slurry transportation held on Feb. 3, 
1976, at Battelle Memorial Institute, Columbus, Ohio; sponsored 
by the U.S. Energy Research and Development Administration, the 
Slurry Transport Association and Battelle Memorial Institute. 220 p. 

Bechtel Corporation. Clean coal energy: source to use economics. 
Final report to ERDA, Jan. 1976. 

Campbell, T.C. and Sidney Katell. Long-distance coal transport: unit 
trains or slurry pipelines. U.S. Department of the Interior, 
Washington, D.C. 

Hudson Institute, Research analysis of factors affecting transportation 
of coal by rail and slurry pipeline, a v. 
Croton-on-Hudson , N.Y., Hudson Institute. April 1976. 

Merfel, Joseph and Dr. Lawrence Vance. A preliminary estimate of the 

impact of the implementation of five proposed coal slurry pipelines. 
U.S. Department of Transportation. Freight transportation digest, 
October 1976. 

Rieber, Michael, Shao Lee Soo, and James Stukel. Comparative coal transporta 
tion costs: an economic and engineering analysis of truck, belt, 
rail, barge and coal slurry and pneumatic pipelines. Urbana, Illinois. 
Center for Advance Computation. University of Illinois. 8 volumes. 
V. 3 — Coal Slurry Pipelines. August 1977. 



505 



3.4,7. Coal Transportation on the Great Lakes * / 

3.4.7.1. Brief Description of the Issue 

Although the movement of bulk ore such as taconite on the Great Lakes 
has been commonplace for some years, it has only been more recently that 
this mode of transportation is being considered a viable means of moving 
western coal to eastern markets. The utilization of extremely large coal 
carriers, especially of the more modern self-unloading type could enable 
shippers to move vast quantities of coal from the Northern Great Plains to 
consumers along the shores of the lower Great Lakes at a fraction of the 
cost of using unit-trains for this purpose. This new technology is not 
without its own special set of problems, some of which are technical and 
others environmental. 

3.4.7.2. Background Information . Prior to 1970, the concept of extensive 
development of western coal was not widely recognized. With the passage 

of the Clean Air Act of 1970, however, coal users mine operators were 
sent scurrying around for sources of coal that they felt would comply 
with the limitations (emissions of sulfur dioxide). As a result, the big 
push for western "low-sulfur" coal began. At the stage of early development 
of these reserves, the most logical approach to the shipping of the coal 
was the use of the unittrain, the combination of locomotives and coal 
cars, usually numbering 100 devoted expressly for the purpose of carrying 
approximately 10,000 tons of coal from the mines straight to the utilities. 
This combination allowed the carriers to insure a quick turnaround since 
none of the cars in the train had to be cut and switched to other routes. 

*/ Prepared by Duane A. Thompson, Analyst, Environment and Natural Resources 
Policy Division. 



506 

To enhance this quick turnaround, unloading terminals were designed to 
allow the emptying of the cars without uncoupling. In some terminals, 
bottom-dump cars are pulled across a trestle and the coal is literally 
dumped through the tracks while the train proceeds forward at a speed 
of about five miles per hour. This efficiency, in conjunction with the 
fact that three of the Burlington Northern main lines either run through 
or are adjacent to the geographic location of the principal coal development 
added up to what many believed to be the most efficient method possible 
for the movement of western coal to market. 

Historically, however, studies have proven that water offers the cheap- 
est mode of transportation for coal, regardless of the source of the mineral. 
According to information contained in the 1977 Keystone Coal Industry Manual, 
a study in 1963 revealed that, "The rail revenue on bituminous coal for all 
lengths of rail haul averaged 10.4 mills per ton mile. On the other hand, 
charges for coal transportation on the inland rivers were less than one- 
third that amount (3 mills per ton mile), and on the lakes and oceans at 
about one-fifth (2 mills or less)." 

3.4.7.3. Bureau of Mines Assessment . In 1970 a study was conducted 

by the Bureau of Mines to determine the transportation of various commodities 

1/ 

including bituminous coal on the Great Lakes. The report included projectioni 
on the transportation to 1995. The Bureau, however, did not forsee any 
coal traffic coming from the Northern Great Plains and indicated that, 
"The bituminous coal resources contributing to the coal commerce of the 

\/ Transportation of Midwest. Iron Ore, and Bituminous Coal on the Great 
Lakes System, by the United States Bureau of Mines, #I.C. 8461, 1970, 
pp. 12-16. 



507 

Great Lakes are in the nearby States bordering on Lakes Ontario, Erie, 
and Michigan." Perhaps the authors, since the Arab oil embargo had not 
yet taken place, assumed that all of the increases in coal production 
would take place in either the Appalachian States or in the Midwest. 

The conclusion of the study was that the bulk of the coal traffic 
on the Great Lakes in 1995 would originate at the docks of Toledo, Ohio , 
would be distributed to points northeastward and northwestward ranging 
all the way to the upper end of Lake Superior. Figure I illustrates the 
distribution of the coal traffic projected by the Bureau. 



Figure I. Projected Bituminous Coal Traffic Flow, 1995. 
Million Net Tons 




Source: Transportation of Iron Ore, Limestone, and Bituminous Coal on 
the Great Lakes Waterway System, with projections to 1995, the 
United States Bureau of Mines, Information Circular #IC 8461, 1970, 
p. 16. 



508 

3.4.7.4. Corps of Engineers Assessment . Later projection, however, 

have arrived at drastically different conclusions than those of the 

2/ 

Bureau of Mines. The Army Corps of Engineers has devoted considerable 
attention to the prospect of increasing coal traffic on the Great Lakes, 
especially in view of the likely development of Northern Great Plains 
reserve development. The Corps feels certain that if a national commitment 
to coal as the primary energy resource materializes, then drastic increases 
in the tonnages of coal being transported on the Great Lakes is assured. 
The concept of shipping coal, as with other bulk commodities has already 
been demonstrated. Unlike the Bureau of Mines, however, the Corps is 
certain that the overall net flow of coal will not be from Ohio ports 
to other points but instead, from the port of Duluth to destinations like 
Chicago, Detroit, and Buffalo. 

According to the study, which was performed for the Corps by A.T. 
Kearney, Inc., total freight traffic on the Great Lakes is expected to 
grow at a modest rate, "even with the expected increase in shipments of 
Western coal. Present tonnage is projected to slighty more than double 
by the year 2000... at which time it will represent about 10% of the total 
domestic marine market." Within this increase, however, there remains 
a great potential for the development of a coal trade and between the 
northern port of Duluth-Superior and utility and industrial consumers 
along the lower portions of the Great Lakes. 

3.4.7.5. Detroit Edison Movement . The action which has initiated 
the actual flow of Western coal to the Midwest via the Great Lakes has 

Ij Personal communication with Mr. George Lykowski and Mr. Robert Mclntyre 
both of the North Central Division of the Army Corps of Engineers, 
U.S. Army, Chicago, Illinois. 



509 

been the signing of a contract between the Decker Coal Co. of Montana 
and the Detroit Edison electric utility to supply its St. Claire plant 
near Detroit. The $180 million deal involves the delivery, by Burlington 
Northern, of low-sulfur coal over the next 25 years to a special terminal 
to be built near the upper end of Lake Superior. (See Figure II.) 

The plant is currently using 2 million tons of western coal annually. 
The maximum consumption will be reached in the early 1980 's with an annual 
consumption of 8 million tons and the utility has contracted for a total 
of 200 million tons through the year 2001. Shipping for the year will be 
finished on December 20, 1977, and will not be resumed until April 1, 1978. 
The utility is currently planning to construct another plant which will 
consume western coaKBelaire Plant). The utility has expended a total 
of approximately $185 million for the conversion of the present facilities 
to the use of western coal and according to the spokesman, the utility 
is not likely to convert back to the use of eastern coal even considering 
the impending requirement to install BACT. Some of the other plants in 
the utility's system, however, have experimented with the practice of 
blending western and eastern coal, but the success of this practice has 
not yet been proven. The utility has also indicated that additional stockpiling 
facilities had to be constructed in order to accommodate the additional 
three month's worth of coal during the winter season and that the company 
has supported the concept of keeping the shipping lanes open during the 
entire season. Even with the stockpiling alterations that had to be made, 
however, the cost adv'antages of shipping the coal in by Lake carriers still 



510 

outweigh the use of unit trains primarily because of the rail tariffs and 
the different combinations of railroads that have to be used in bringing 
the coal East. 

Another study on the subject revealed that other utility companies 

4/ 

are interested in the concept of burning western coal. 

In addition to Detroit Edison, at least five other companies have 
made commitments for the delivery of western coal which will total ap- 
proximately 27 million tons. 



Current and Potential Commitments for Lakewise Shipment of 
Western Coal (in million tons per year) 



Company Tons 



Detroit 8 

Cleveland Cliffs Steamship Co. 2 

Upper Peninsula Power Co. I 

Niagara Mohawk Power Co. 12 

Central Maine Power Co. 2 

Montaup Electric Co. 2 



Total 27 



5/ 



2J ' Personal communication with Mr. Rick Sylvain of the Detroit Edison Co. 

4/ Western Coal Shipments on the Great Lakes , United States Department of 
Energy, Argonne National Laboratory, October, 1977. 



5/ Ibid . , p. 20. 



511 

3.4.7.6. Through Traffic to New York . Another interesting possibility 
which was included in the Argonne report is the movement of western coal 
to the New England areas by way of the Great Lakes to a planned port at 
Buffalo with subsequent movement to various points in the Northeast on 
Conrail. The port, which is in the preliminary stages, by the New York 
Department of Commerce and the Niagara Frontier Transportation Authority, 
will have the capability of handling approximately 12 million tons of 
Western coal. 

A discussion paper by the Honorable John J. LaFalce describing the 

merits of just such a plan to import western coal into New York by way 

of the St, Lawrence Seaway was reprinted in the June 10, 1977 issue of 

the Daily Congressional Record . According to the Congressman, New York 

already has the "capacity to trans-ship ... low-sulfur coal by rail, with 

the potential of reviving that major [rail] industry in a major way." In 

addition to the possibility of shipping western coal via the railways, 

the Congressman also suggested that an "All-American" canal could be 

constructed (Lake Erie-Lake Ontario Waterway): 

This proposal — essentially to build a canal large enough 
to handle the biggest Lake shippers across the Niagara Penin- 
sula from North Tonawanda to Wilson — is one that has been with us 
literally for decades. It would parallel the Welland Canal and, in 
all likelihood, siphon off so much traffic from the Welland that 
that 40 year old canal would be closed to operations. b_/ 

Although the feasibility of such a canal was studied by the Army Corps 

of Engineers in 1973, and found to be uneconomical. Congressman LaFalce 

suggested that the study was too narrow in its scope because the feasibility 

6^/ Honorable John J. LaFalce, Discussion Paper for Future Transportation/ 
Energy Developments. Inserted in Congressional Record, June 10, 1977. 
p. H5735. 



512 

of the canal was studied as a separate entity and not as a component 
of an integrated freight-transportation system which would include the 
enlargement of the New York State Barge Canal. 

3.4.7.7. Constraints and Problems . Although one of the causes for concern 
is the speed with which the coal can be transferred from the ships to 
shore facilities, this problem is being approached with new design concepts 
in coal carriers. The Kearney report also determined that many of the 
points of interface for the commodities being moved on the Lakes were, 
"far behind the level of available technology." In order to alleviate 
this difficulty, the Orba Corporation of West Caldwell, N.J., is designing 
coal carriers in the thousand-foot range that will be capable of self-unloading 
These vessels will have the capacity to carry approximately 62,000 tons 
of coal and when operational, will be part of an integrated system of 
loading, storage, and coal stockpile retrieval equipment also being designed 
by Orba. 

Increased coal on the Great Lakes is not without its unique technical 
and environmental problems. When undisturbed, the upper Lakes are closed 
with ice for about three months of the year, and, unfortunately, these three 
months are the ones during which adequate coal supplies are essential for 
utilities. In the absence of efforts on the part of the Coast Guard to 
keep the shipping lanes opened all winter, utilities and industrial consumers 
on the lower end of the Lakes must maintain, in addition to their reg- 
ular stockpiles for unforeseen contingencies, at least three months of 
stocks to tide them over the icebound season. In addition, on the upper 



513 

end of the Lakes, the ports would likewise be required to maintain a stock- 
pile facility in order to receive the shipments of the unit trains coming 
in from the Northwest Great Plains mines. 

Furthermore, this stockpiling requirement would also mean that a 
year's worth of coal would have to be transported during the remaining 
nine months of the year. This requirement could conceivably increase 
the pressures on the locks that all of the coal shipments coming in from 
the Northern Great Plains would have to negotiate. 

The Army Corps of Engineers has already demonstrated that the shipping 
channels can be kept open the year around, but at considerable expense and 
effort on the part of the Corps. Additional icebreakers would be needed 
for the operation and spokesmen for the Corps have indicated that congres- 
sional funding would be required for the purpose. Furthermore, many of 
the associated facilities, including docks and the locks at the juncture of 
the Lakes, may have to be upgraded in order to keep pace with the increased 
ship traffic. 

On the environmental side, additional questions remain that have yet 
to be answered. The Corps is presently engaged in the preparation of a 
feasibility study to determine the impact of increased ship traffic, es- 
pecially during all four seasons. The first draft of this study should 
be available early in the summer of 1978 with the final draft scheduled 
for the end of this year. Among other questions that will be addressed, 
the study will try to determine whether the increased agitation of the water 
in the upper Lakes, especially during the winter, will have any detri- 
mental effect on the flora and fauna of that area. Also, there remains 
some question as to whether or not continual ship traffic accelerates 

24-786 O - 78 - 34 



514 

the erosion of the beaches and flexes the remaining ice at each side of 
the shipping channel in such a manner as to loosen pilings on docks and 
piers at the Lake's edges. Finally, the whole question of the effects 
on the recreational activities of the residents of the areas in and around 
where the coal will be moving will have to be addressed. Many island 
dwellers use the ice for crossing in the winter months and would have to 
seek other means of crossing to the mainland if the shipping channels 
were kept open. 

3.4.7.8. Analysis and Conclusion . Indisputably, western coal shipped 
via the Great Lakes represents a great source of energy to utilities and 
industrial consumers in the Mid-western States, especially those clustered 
along the shores of the lower Lakes and who could. consume the coal without 
significant traditional handling. Certain related policy questions, however, 
will have to be addressed by Congress if this is considered a desired 
course of action. For some time, the railroads have maintained that coal 
shipments by water have been subsidized by the Federal Government through 
the maintenance of lock and dam systems on the Mississippi, Ohio, and 
other rivers with public funds without any kind of a user charge. This 
subsidization, according to the railroads, has encroached upon the most 
lucrative segment of their business. With the rail routes to the western 
coal deposits amenable to the unit train concept, the railroads may protest 
even more vehemently any action on the part of the government to keep 
the shipping lanes open year around for coal carriers on the upper Great 
Lakes at the expense of profits that could be theirs. While the primary 



515 

western railroads would still share in the revenue of shipping coal from 
the minemouth in the Northern Great Plains to the proposed ports in 
Duluth/Super ior , many of the interconnecting rail lines in the Midwest 
would be effectively cut out of this part of the western coal transporta- 
tion scene. Many of these midwestern rail companies are the same ones 
that already have to compete with barge traffic on the inland water- 
ways and which have been looking at the prospect of transporting 
western coal with great enthusiasm. 

Increased shipments on the Lakes, however, are likewise dependent 
upon the same factor that affects the overall development of the western 
coal deposits, namely, the degree to which demands on this coal will be 
adversely affected by the requirement upon consumers to install the "best 
available control technology." The Corps of Engineers maintains that be- 
cause of the sheer magnitude of commitments already made by coal companies, 
railroads, and consumers to develop this coal, technology to make it ac- 
ceptable environmentally and economically will be developed in much the 
same way as the pelletizing and shipping of taconite from the upper Great 
Lakes to the steel mills in Northern Indiana and Ohio. The idea of some 
beneficiation of western coal perhaps through solvent refining certainly 
has merit and could offset some of the advantages of higher-Btu eastern 
coal . 



517 

3.5. OTHER POTENTIAL ISSUES 



519 

3.5. Other Potential Issues * / 

During the preparation of this volume, numerous additional potential 
issues were suggested for treatment, but were not developed as were the 
foregoing. The reason in some cases was the lack of certainty that the 
issue would become Important enough to Interest Congress; in others, the 
lack of information to draw upon. Some of these potential issues are: 

3.5.1. Deregulation of certain transportation industries . This public 
policy question would apply most importantly to regulated interstate truck 
lines and air carriers. Neither of these modes currently carry substantial 
quantities of energy materials, and investigation suggested that their 
deregulation would have little or no effect on the movement of energy 
materials. There is substantial truck movement both of coal and petroleum 
products, mostly quite local, and almost entirely privately owned. The 
bulk movement interstate of LP gases is longer in haul, but is similarly 
privately owned and would not be affected by deregulation, 

3.5.2. The potential for renewed maritime shipment of coal on the eastern 
seaboard . From I860 to 1940, a substantial amount of coal mined in Appala- 
chia was shipped from harbors in the Hampton Roads area to points further 

up the Atlantic Coast. A flow diagram on page 45 , (figure 2 a) of the first 
volume of this study shows the former extent of this traffic. The de- 
predations of German submarines during two wars all but killed the coastal 
trade in coal. With the current renewed emphasis on coal, and the economies 
of large bulk carriage by water, it is possible that such traffic will 
revive over the next several years, A port for loading of western steam 

*/ Prepared by John W. Jimison, Analyst, Environment and Natural Resources 
Policy Division. 



520 

coal is in planning for the Houston area. If industries and power plants 
in New England, the Southeast, or Gulf regions convert to coal, or 
base new growth on coal, they may find that the most economic form of 
movement to them will be by large bulk carrier from a coastal loading 
point. The question of the Jones Act requirements for U.S. -built, U.S.-crewed 
ships to be engaged in this trade will become central, especially since 
there are currently few if any U.S. -flag coal carriers. Port facilities 
construction, competition with railroads, and competition with possible 
slurry pipelines will be other issues. On the west coast, similar traffic 
could arise based on Alaskan coal (see 3.2.4.). 

3.5.3. The transportation of Alaskan North Slope natural gas liquids . In 
1976, proven reserves of 407 million barrels of natural gas liquids were 
added to the U.S. total from the Prudhoe Bay field of Alaska, six years 
after the proven reserves of oil and dry natural gas were added. Because 
of technical problems, it initially appeared that the transportation of these 
natural gas liquids might not be possible in either the Alyeska crude oil 
system or the proposed natural gas pipeline system. In this case, they 
would have required another form of transportation, or would have to have 
been consumed in the North Slope. Discussions with industry experts, however, 
indicated that those technical problems could be solved by sending some 
of the liquids through mixed with crude oil, and others under high pressure 
in the natural gas line. That which cannot be shipped will be used to 
fuel North Slope operations. None will be wasted. If all of these plans 
work out as proposed, there will be no need for additional transportation 
capacity. Current decisions on the pressure at which the Alaskan gas line 



521 

will operate in Canada, and its diameter, may effect the ability to put 
the liquids in the gas stream, and may thus revive the question. 

3.5.4. Transportation of oil and gas developed on the Atlantic PCS. The 
offshore continental shelf of the Atlantic may become a major new source 

of energy supply. Important issues are raised by questions of leasing 
policy, environmental protection, siting of coastal facilities, manage- 
ment of onshore impacts, and other questions. The transportation of any 
oil or gas developed offshore in the Atlantic will obviously require new 
capabilities. For oil, it would appear that tank barges or other vessels 
will be used for transportation to shore, given the distance from the 
coast of the potential fields and the problems of underwater pipelining, 
unless the quantity discovered is so large as to make a pipeline advantageous. 
For the gas, pipelines will be necessary, but the technical problems are 
fewer and the environmental risks lower. New oil and gas deliveries would 
tie neatly into existing refineries and pipelines, respectively. On balance, 
it appears that the problem? of transportation of Atlantic OCS oil and 
gas resources are subordinate to the other issues of Atlantic OCS development, 
and do not face political obstacles or technical constraints of equal 
importance . 

3.5.5. Transportation of materials to offshore, nuclear power plants . 
One idea for siting nuclear power plants has been to put them well off- 
shore where they could not be in a populated area and where theRe would 
be ample cooling water available. Among the requirements of such plants 
would be new transportation systems. Nuclear fuel materiels would be 
presumably taken to the offshore plant by barge or other vessel, and would 
be susceptible to the same risks that other water traffic is. Containers 



522 

would have Lo be made so that they could be readily salvaged and resistant 
to any damage before such highly radioactive nuclear materials could be 
shipped in sensitive coastal areas. The electric power would either be 
transmitted to shore by cable or perhaps used to manufacture hydrogen 
and oxygen for sea water through electrolysis, carried to shore by pipeline. 
Similar transportation problems would be posed by electricity generated 
by the proposed ocean thermal (OTEC) technology. Such nuclear plants are 
far from reality, although the idea is not dead. Again, however, the trans- 
portation problems will be minor compared to the other problems faced 
by such proposals. 

3.5.6. Railroad-owned coal reserves and the commodities clause . The com 
modities clause of the Hepburn Act prohibits railroads from carrying any 
product or commodity which they own except lumber. It applies to coal, and 
has been suggested as an obstacle to the development of western coal, much 
of which is owned by the railroads. Numerous means have been found, however 
of circumventing what might appear to be the dampening effect of the com- 
modities clause. Corporate restructuring, whereby coal is moved by a railroa 
that is owned by an affiliated or subsidiary enterprise of the railroad, 
is one approach; use of a middle man to whom the coal is sold, who owns 
the coal during shipment, and from whom the customer buys it, is another. 
The most common way for railroads to obtain the value of coal they own 
without themselves mining it is to lease the coal reserves to another 
party. Such leases may be conditioned on transportation of the coal over 
the lessor's railroad. There seem to have been few if any complaints that 
the railroads are using such advices in a way to promote their coal 



523 

or their client's coal at the expense of other shippers ' coal , or that 
other shippers have been discriminated against. Protection from such 
discrimination was the original purpose of the commodities clause. Hence, 
changes in the commodities clause would apparently have little purpose 
either for faster development of western coal or greater economic support 
for the railroads, at present. 

3.5.7. Transportation of products from minemouth conversion . Current 
markets for western coal outside the intermountain area are primarily 
electricity generation in the Central States. For the future , expansion 
of these markets is foreseen, but the major issue beyond greater direct 
use of western coal is its conversion at the mine mouth to alternate energy 
forms for a greater diversity of uses throughout the U.S. economy. The 
alternate forms under consideration are as electricity introduced into 
the existing transmission network and as synthetic natural gas or synthetic 
oil for introduction into the oil and gas network already in place. 

The extent to which coal will be converted in the West to alternative 
forms for consumption throughout the U.S. is itself a major issue and cannot 
be divorced from transportation issues. The major factors bearing on the 
conversion issue are water supply constraints in the West, energy losses 
in conversion, location of environmental impacts (at point of mining or point 
of use), socio-economic impacts of mine-mouth conversion, and economics 
of alternative sources of oil and gas at points of use. Energy transporta- 
tion per se is a minor consideration in the over-all issue area, being confined 
to well-known factors of electricity transmission and pipelining. 



524 

A number of wide-ranging studies have been made of these factors over 
the past five years. All have shown that the number of variables is so 
large, and the individual circumstances so unique, that no generic con- 
clusion favoring any one approach to western coal use in non-western 
markets can be reached, other than that shipping coal by rail for electricity 
generation is currently a viable option.* 

3.5.8. Liability of barge operators for oil spills . Barge traffic in oil 
is substantial on the inland waterway system. Recent environmental re- 
quirements imposing penalties for spills threaten barge operators with such 
potential liabilities that insurance is difficult or impossible to afford. 
Although allegations have been voiced that unlimited liability for oil 
spills would impact severely on barge operations, the issue and data have 
not been fully developed, and the impacts may be overstated. 

3.5.9. Natural gas pipeline compressor fuel . A substantial portion of the 
natural gas put into interstate pipeline systems must be used to operate 

the gas-fired turbine compressors which keep the rest of the gas flowing 

through the system. There have been questions about the efficiency of this 

use of natural gas, with allegations that electric compressors would save 

much energy, or that liquids could be used. The cost of replacing current 

compressors is so substantial, however, that no one has proposed other options 

for existing systems. The gas shortage, in slowing or halting the growth 

of natural gas pipelines (see 3.1.10), has probably also reduced the 

importance of this issue to insignificance, except in connection with 

1/ 

the Alaskan Highway Gas Pipeline and other new construction. 

y For a treatment of this possibility, see statement of Robert W. Rether Ford, 
Consulting Engineer, in hearings by Council on Environmental Quality on 
Alaska Natural Gas System. Reproduced by Senator Stevens in Congressional 
Record, June 27, 1947, p. 10803. 



525 

3.5.10. Spontaneous Combustion of Coal. One problem which may arise 
in the movement and storage of western coal is that of spontaneous com- 
bustion. Western coals tend to have a higher moisture content, and can 
spontaneously ignite during long shipments or in storage piles more 
readily than eastern coals. Weight loss from evaporation may also occur. 
Special precautions may be required to prevent such problems, but will 
probably not call for any particular government actions. 

3.5.11. Natural Gas Pipeline Divestiture. Most natural gas pipelines 
are owned by companies which have no structural connection to either their 
suppliers or their distribution company customers. There are, however, a 
few vertically integrated natural gas companies which operate transmission, 
major production, and distribution facilities. In addition, most of the 
major pipeline systems operate a gas production subsidiary, few of which 
supply a large percentage currently of the pipeline's throughput, but 
which will probably increase in importance. The proposal has been made 

by Senator Metzenbaum (S. 1448, 95th Congress, 1st. Session) that the 

natural gas industry be required to divest itself of activities other 

than transmission. This has given rise to fear in the industry that the 

gas supply developed for the interstate market by pipeline-owned production 

companies would be lost to the intrastate market if these companies are 

divested. On the distribution side, divesting the distribution aspects 

of a unified transmission and distribution system would require much additional 

metering and the creation of additional administrative expense by having 

two entities managing operations that one currently manages. 



526 

Both the transmission and distribution segments of the natural gas 
industry are fully regulated (3.1.11), unlike the oil industry, and are 
not common carriers. The room for anti-competitive market abuse by gas 
utility operations with obligations to serve and fixed service areas is 
much less than that for oil operations. Allegations of such abuses have 
been few and infrequent. The production arms of pipeline companies are 
also regulated in the wellhead price to be charged, and would probably 
remain regulated so after deregulation of independent producers, although 
their prices would similarly rise. 

Because of these operational and regulatory differences between the 
gas and oil industries, the meaning of divestiture is quite different, 
and the issue of divestiture in the gas industry would seem to be one 
of considerably less moment. 



527 

3.6. SUMMARY AND ANALYSIS 



I 

I 



529 

3.6. Summary and Analysis */ 

This volume contains treatments of forty identified energy transportation 
issues or problems. Each treatment is intended to stand on its own; how- 
ever, the volume as a whole would be much less valuable if it did not 
attempt to integrate these separate topics into a unified format relating 
them to larger themes and topics. That is what this section attempts to 
do. The energy transportation issues are examined first in the context 
of each of the major fuels, then in the context of each of the major modes. 
Some general thoughts, analysis, and conclusions are also provided. 

3.6.1. Summary and Analysis by Fuel 

3.6.1.1. Natural Gas. The use and distribution of natural gas will be 
substantially affected by the resolutions of the issues described in this 
volume. In turn, policy decisions on supply, source, and pricing will deter- 
mine the relative importance of transportation issues related to natural 
gas. 

The quantity of natural gas available to the energy consuming areas 
of the Nation will depend in large part on new supplies from Alaska (3.2.6.), 
overseas in the form of LNG (3.3.8.)**/, and Mexico (3.3.6.). These supplements 
to the declining stock of domestic natural gas may be critical to continued 
service to the higher priority gas market after a few years; solving the 
related transportation questions may be critical to the availability of these 
supplements . 

V Prepared by John W. Jimison, Analyst, Environment and Natural 
Resources Policy Division. 

**/ Refers to chapter, section, and subsection where discussion of this 
topic takes place in this volume. 

/ 

24-786 O - 78 - 35 



530 

That the natural gas shortage has brought the prospect of change to 
the natural gas pipeline industry also suggested not only by the section 
directly concerning the possible changes (3.1.10), but also by the sections 
dealing with the abandonment of natural gas pipelines which the shortage 
has made surplus: the Florida gas line proposed for petroleum products 
(3.1.14), the El Paso line proposed for Alaskan crude oil (3.2.1.3.), 
and others (see 3.1.1.16. and 3.3.8. for possible examples). It is possible 
that the gas pipeline industry will not operate at the turn of the century 
in the same manner that it operates today; it is probable that the 
sources of supply which feed the pipelines and the basic directional pattern 
of their service will change drastically. Numerous possible scenarios 
are possible, depending on policy decisions and technological developments. 

A situation can logically be envisioned, for example, in which the 
natural gas producing regions of the Gulf are no longer sending enormous 
flows of natural gas to the North and East. Instead, Alaskan gas may be 
substituted for Canadian imports and Gulf Coast production as well in 
the upper Great Lakes region, and the Pacific Northwest. LNG may supply 
much of the East Coast seams, along with perhaps some natural gas from 
the Atlantic DCS, coal seams, and Devonian shales, and gas substitutes 
in the form of imported LPG (3.3.9.), coal gasification, and SNG produced 
from imported liquids. Some interstate shipments from Gulf supply areas 
will obviously continue, but the Gulf region's natural gas resources may 
be more and more focussed on meeting its own growing demand. Even after 
deregulation, intrastate needs may monopolize new gas supplies as they 
do now, outbidding interstate users who must pay higher transportation costs. 
The availability of such supplements as methane from geopressurized reservoirs 



531 

and imports of natural gas from Mexico (3.3.6.) may begin to prove important 
for continuing interstate flows or supplementary supplies to the Gulf region 
itself. The West Coast is likely to become more reliant on Alaskan natural 
gas, LNG from overseas, and perhaps direct Mexican imports, and less reliant 
on continued deliveries from New Mexico, Texas, and points East. 

If correct, this scenario would imply that the three major energy con- 
suming regions would each be gradually turning to different sources of this 
premium fuel, and away from dominant reliance on the domestic reserves 
of the Gulf Coast. Obviously the massive pipeline capacity constructed 
to supply gas from those reserves would become increasingly underutilized 
for its original mission, and alternatives to maintain its value would be 
sought. These might include movement of coal slurry from eastern coal 
fields (3.1.16.) or movement of other materials such as water. The politics 
of the natural gas situation would also change markedly, as regional 
dependence on foreign imports became a more important concern (see 3.3.6., 
3.3.8, and 3.3.11.), the transactions between current producing States and 
consuming States declined, and the prices for all gaseous fuels reached 
or exceeded equivalence with world oil. 

The extent to which this scenario would become reality 
as opposed to other possible scenarios would depend on several key 
factors . 

One is the ongoing and basic debate over pricing of natural gas, 
and the related question of what the supply response to higher prices 
will be from the domestic natural gas resource base. The transportation 
pattern for natural gas, and the transportation issues which become important 
for Congress or others to solve, will obviously be much different if 



532 

bountiful new gas supplies are located in traditional producing regions 
than if the recent rapid decline in production there continues. 

Another critical decision which will affect the choices among and accept- 
ability of the alternative gas sources is that concerning the incremental 
pricing of new supplies. A general policy prescribing incremental pricing 
for all new sources, or prescribing rolled-in prices on a company-by-company, 
regional, or national basis would have profound effects on the ultimate | 
supply distribution pattern of natural gas and hence on the transportation 
issues involved in effecting that pattern. If some new sources are in- 
crementally priced while others are rolled-in, the effects would be even 
more striking. Thus the resolution of this incremental pricing question, 
like the resolution of other basic pricing and supply source issues, can 
largely determine the relative importance of the issues related to natural 
gas transportation. 

A third general question which will have profound effects is that of 
natural gas usage patterns at higher price levels. Will demand fall as prices 
begin to exceed oil-equivalent levels, or continue to rise based on new 
high priority and nonconvertible uses? The market reactions to future 
events, and the policies designed to shape that reaction, will also help 
to determine the need for solutions to the problems of transporting gas 
to meet the demand. 

A fourth general policy question might be the perception of gas sources 
and supplies from angles other than their fuel-related aspects. The issue 
of safety and risk to the public from massive LNG imports (3.3.8) is related 
to this, as is the question of hazardous material regulations, which cover 



533 

LNG moved in tank trucks (3.1.8.). The question of vulnerability to political- 
ly motivated interruptions occurs not only on the international side (3.3.8., 
3.3.6., 3.2.6., and 3.3.9.), but also on the domestic side with regard to 
sabotage (3.1.12.). 

The conclusion is that the actual future supply and distribution pattern 
will determine how critical the transportation issues described in this 
volume are, and will be itself determined by the answers to basic questions of 
policy, technology, and good fortune. 

3.6.1.2. Oil. Numerous issues are identified and described in this 
volume that deal with oil movement. Unlike natural gas, where the uncertain- 
ties of domestic supply are great, there seems to be a relatively good con- 
sensus about the quantity of conventional domestic crude petroleum avail- 
able over the mid-term. The availability of other fuel liquids such as 
oil from shale or synthetics, are much more questionable, but substantial 
quantities are unlikely in the next ten years. Hence, the growing need for 
liquids has been met by imports and a major proportion will continue to 
be supplied by imports indefinitely. 

The issues related to oil movement perhaps resolve themselves most neatly 
along domestic and international lines. Within the domestic side, they break 
down among those which are general and those which are specific to regional 
movements. For example, the section on the disposition of the surplus of 
Alaskan crude oil on the West Coast, (3.2.1.), the longest and most com- 
prehensive issue discussion in the volume, focusses on the logistical quest- 
ion of bringing Alaskan oil to where it is needed the most, in the Central 
U.S. But the pipeline divestiture issue (3.1.11.) would affect all regions. 



534 

In addition to the West Coast surplus question, domestic oil transporta- 
tion issues with a regional focus include, the related question of crude oil 
supplies for Northern Tier refiners (3.1.1.); the conversion of the Florida 
gas pipeline to petroleum products movement (3.1.14.); the question of ad- 
ditional crude oil transportation capacity in Alaska (3.2.2.) and of the rates 
for the existing Alyeska pipeline (3.2.5.); the impact of proposed waterway 
user changes, which w'ill affect oil shipments primarily along the Mississippi 
and Ohio Rivers systems (3.1.9.); The Jones Act requirements for coastal 
shipments (3.2.3.); and, in part, on transportation of oil from the Strategic 
Petroleum Reserves currently being filled (3.3.3.). 

In addition to the important pipeline divestiture question, transporta- 
tion issues which have impacts on oil movement across the Nation are the 
question of allowing heavier trucks to utilize the roads (3.1.2.); requiring 
heavy trucks to meet fuel efficiency standards (3.1.3.), and safety stand- 
ards for handling of hazardous materials (3.1.8.); and the vulnerability 
of transportation systems to sabotage (3.1.12.) and other interruptions 
(3.1.15.). 

The international issues primarily relate to tanker-borne imports, 
their safety, economics, and security. The regulation of tankers to pre- 
vent accidental discharge of oil is a key issue in both U.S. waters (3.3.2.) 
and internationally (3.3.7.). The economics and pattern of oil import move- 
ment will be greatly affected by the resolution of the deep-water port ques- 
tion (3.3.1.). The question of the current surplus of tankers on the world 
market (3.3.4.) and the issue of cargo preference — a possible requirement 
that a given percentage of oil imports being carried in U . S tankers — together 
relate to the cost of international oil movement. Finally, the security 



535 

of imports is addressed (3.3.5.) as well as the workability of measures 
to improve that security by building an emergency inventory of potentially 
needed oil (3.3.3.). 

Questions of imports of oil from Canada are referred to in connection 
with the Northern Tier refiners (3.1.1.) and the distribution of surplus 
Alaskan oil (3.2.1.). The international pipeline treaty (3.3.11.) deals 
with the protection and economics of those movements of oil which cross 
Canadian lands. 

A major goal of the President's National Energy Plan is to reduce oil 
imports and build reliance on domestic fuel sources, although conventional 
domestic oil sources are declining except in Alaska. Obviously, therefore, 
the connection of the resources of Alaska to the major oil distribution 
pattern in the eastern half of the contiguous States ( see map 13, Volume I) 
is one transportation issue with very significant effects on the achievement 
of our national energy goals. The 1973 decision to route Alaskan oil to 
the West Coast of the U.S. has now resulted in that oil being in surplus 
there; whatever planning that may have been done related to further disposition 
of Alaskan oil to U.S. consumers, was obviously inadequate and untimely. 

A second major theme of policy related to oil is the protection of 
our national interests from the insecurity of our overseas imports. Although 
physical interdiction of our supply lines may be unlikely, (3.3.5.), political- 
ly inspired interruption remains a potent threat. Thus we have begun to 
store oil for such an event (3.3.3.), and have worked to assure the security 
of pipeline imports (3.3.11.) as well as tanker imports. We have considered 
whether the additional security of such movements if they were carried in 
U.S. -flag ships, would be worth the additional cost (3.3.10.), and have 



536 

so far decided that it would not. We have only begun to recognize the threat 
of politically inspired interruption of our domestic flows (3.1.12.). 

A third theme has related to the economics of oil transportation. The 
United States would like to be able to offset the rising cost of oil paid to 
producers, as much as possible, by savings of the cost paid to transporters. 
Thus the Nation is interested in building deepwater ports in order to utilize 
the efficient supertankers that cannot be accommodated in our shallow harbors 
(3.3.1.). Part of the motivation for consideration of pipeline divestiture 
or regulatory reform (3.1.11.) is the notion that less integration among 
sectors of the oil industry, or less profit from rates for pipeline move- 
ment, would save consumers money. The same notion is involved in the 
Alaska pipeline rate dispute (3.2.5.). If larger tank trucks could be legal- 
ly used on the roads (3.1.1.), or if these trucks used less fuel to move 
fuel (3.1.3.), the unit cc of distribution of oil products might slip 
perceptibly. The use of otherwise surplus natural gas pipeline capacity 
to carry petroleum products to Florida may save consumers money and add 
to security as well (3.1.14.), although the jobs of some maritime workers 
may be the cost of obtaining these economies. Proposals to amend the Jones 
Act also have an economic root (3.2.3.). The economics of oil movement in 
one area, however — on the inland waterway system — may be deliberately 
worsened to remove what some have argued is an unwarranted governmental 
subsidy to carriers (3.1.9.), 

This apparent desire for economic savings from oil transportation is not 
without a countervailing force which is related to the protection of people 
and the environment, however. Improving the record of spills and accidents 
is expensive, and the opposition to many of the proposals for more 



537 

economic transportation options is founded on the fear that they would also 
be more pollution-prone and dangerous. This theme adds a third partner 
to the dance of economics versus security in the area of tanker imports. 
As greater safety and cleanliness are required (3.3.2.), the costs of ship- 
ment rise toward the levels required by U.S-flag ships, which are generally 
safer and cleaner, but the likelihood of savings from low price surplus foreign 
tankers or deepwater ports is diminished. The international community may 
not be willing to impose on itself the same standards, and therefore costs, 
that we deem necessary (3.3.7.). The cost of hazardous shipment protection 
on the highways and rails similarly effect the economics of such movements 
(3.1.8.). 

The mix of motivations that are expressed in the four themes running through 
these oil transportation issues — import reduction, security of supply, 
economics, and environmental protection — are the same as those which 
permeate the overall energy policy questions. How we sort out policies which 
respond to all of these concerns in regard to the general energy problem 
may guide us in their resolution on the subissue related to oil transporta- 
tion. On the other hand, how we weigh and resolve conflicts among such 
overall themes in regard to oil transportation issues may eventually deter- 
mine their resolution on the larger scale. 

3.6.1.3. Coal . Transportation questions have more impact on coal 
production and use patterns than on any other fuel. As the Nation attempts 
to maintain its energy supply and increase it, the emphasis on coal use will 
also increase. As in the natural gas area, the answers to some of the 



538 

supply questions will indicate the importance of the transportation issues. 
In the coal area, the transportation issues will largely be framed by ref- 
erence to the supply needed. The quantity of coal demanded and its charac- 
teristics will determine which coal transportation issues are vital prob- 
lems and which ones will never become significant. 

One key to the resolution of these unknowns may be the suitability of 
different coals under the air quality laws. Simplifying, there are three 
major areas of coal supply in the United States: (1) the eastern areas, 
uncompassing both the Appalachian coal fields and those in Illinois, Indiana, 
and western Kentucky; (2) the western coal fields, including the Northern 
Great Plains region and the southwest coal areas of Colorado, Utah, Arizona, 
and New Mexico; and (3) Alaska. The first two areas are currently involved 
in active U.S. coal commerce; the third is not. 

» 

Again simplifying, the eastern coals tend to be higher in energy 
content and sulfur content than the western coals. On balance, they are at 
a disadvantage in terms of compliance with restrictions on air pollution 
compared to western coals. If their disadvantage were neutralized, how- 
ever, by the requirement that all coal burning installations install equi- 
valent air pollution controls such as scrubbers or some designated BACT 
(best available control technology), the relative future demands for coals 
from the two basic regions would be greatly altered. This question is dis- 
cussed in 3.4.1. The applicable air quality requirements thus become one 
threshold issue in any discussion of the transportation questions concerning 
coal . 

The environmental impacts of strip mining also play a role, even 
after passage of the recent strip mining law, by altering the economics of 



539 

production of strip-mined coal in ways that are as yet not entirely known. 
Almost all western coal is strip-mined, while most eastern coal is deep- 
mined. Eastern coal is more susceptible to labor problems than western 
coal. Federal leasing policies are also involved in eastern versus west- 
ern coal development. 

Once such issues related to the relative value and economics of dif- 
ferent sources of coal supply are sorted out, the transportation dimensions 
of getting that supply to market will become clear. 

To understand the factors involved, one might consider two hypothetical 
and generalized future scenarios: Scenario A, in which the environmental 
advantages of consuming western coal remain strong under clean air laws, 
the expenses related to the stip-mine controls do not neutralize the econ- 
omics of that form of mining, and Federal leasing resumes; and Scenario B, 
in which eastern and western coals require equal air quality investments, the 
economic advantage of strip mining is substantially reduced by the costs of 
reclamation and environmental protection, and leasing of Federal coal in 
the West does not resume. These two scenarios take the logistical dimension 
of future coal supply to the logical extremes. The most realistic scenario 
might be a mix of these factors, but for the purpose of illustrating how 
the transportation issues may vary in importance as a function of these 
factors, these two scenarios serve. 

In general, under Scenario A, western coal production would grow rapid- 
ly, impelled by demand, and would penetrate markets deeply in the East and 
the South. The primary transportation issues would be those related to 
western coal production (section 3.4. generally), and eastern coal produc- 
tion would continue to stagnate. Under Scenario B, however, western coal 



540 

production would grow only moderately to cover current commitments and de- 
mand growth in nearby regions of the Midwest and Southwest. Eastern coal 
production would grow rapidly to serve the major demand region of the East 
and would probably serve essentially all demand east of the Mississippi 
River. Eastern coal would provide strong competition to western coal for 
burgeoning markets in the Gulf region, buoyed by its energy content 
advantage and possible transportation advantages resulting from the internal 
waterway system and potential utilization of excess pipeline capacity. 

The transportation issues associated with coal development would differ 
substantial ly . 

Under Scenario A, for example, the question of coal slurry pipelines 
(3.4.6.) in the West will be less a critical issue than under Scenario B, 
because the maximized demand for western coal will provide enough growth 
in traffic that coal slurry pipelines can be built where they are more 
economic than railroads and the railroads would have enough other coal 
traffic to prosper. Under Scenario B, with western coal expansion held 
down, the importance to the western railroads of obtaining the new traffic 
that did arise, and the competitive injury to them of losing that traffic 
to new coal slurry pipeline, would be greater (3.4.2.). 

Under Scenario A, traffic on the Great Lakes in western coal moving 
to eastern consumers may become a major flow, perhaps all the way to New 
York and New England (3.4.7.). Under Scenario B, however, the current move- 
ment on the Great Lakes of eastern coal may expand, and beyond current commitments 
western coal traffic would not grow. 



541 

Under Scenario A, the western railroads would probably not only remain 
healthy, but increase their coal business dramatically. While the more 
troubled eastern lines would not receive the shot in the arm from coal 
traffic they might obtain under Scenario B, they would perhaps have some long 
distance western coal traffic over their lines (3.1.7.). Under Scenario B, 
however, the coal movements over eastern railroads might grow, perhaps pro- 
viding a new base of economic support, or perhaps giving rise to new competi- 
tion from coal slurry pipelines (3.1.16.) or bulk power transmission (3.1.13.) 
The railroads, as an industry, would probably fare best under Scenario B 
providing that coal slurry pipelines were not built in the West. Even 
with coal slurry pipeline right-of-way legislation, it is possible that the 
railroads could do well under different regulatory or statutory treatments 
(see 3.4.4. and 3.1.7.). 

Under Scenario A, the growth of coal traffic on the river system would 
be less than under Scenario B, except to the extent that intermodal ship- 
ments of western coal took place (3.4.5. and 3.1.9.). The overall vulnerability 
of coal traffic to weather-related disruption would increase under Scenario B 
because of the greater reliance on the waterway system and the greater like- 
lihood of freeze-up of hopper cars carrying wetted-down eastern coal (3.1.15.). 
In addition, the possible impact of waterway users charges would be greater 
(3.1.9.). Under Scenario B, the maintenance of roads in the Appalachian region 
may become a more critical question because of the enlarged truck traffic 
over them (3.1.4.). 

The question of local impacts of increased rail traffic (3.4.3.), while 
currently looked at mostly in terms of western rail traffic, would perhaps 
carry equal weight under either scenario. 



542 

The third general area of domestic coal production, Alaska, is not likely 
to be a factor in coal movement for years, and only then on the West Coast, 
under either scenarios (3.2.4.). It is possible that western coal will 
be competitive with Alaskan coal on the West Coast under certain circumstances, 
or that coal demand there will not arise despite the shipment of Alaskan 
oil to the East. 

Finally, it does not seem likely that major questions will arise of 
imports or exports of coal — coal will remain free of the international 
complications that affect all the other fuels, and particularly oil and 
gas. One possible exception to this may be if imports of coal from Canada, 
utilizing existing pipeline capacity, were priced below coal from 
domestic producers. There is a recent proposal to ship coal slurry from 
Alberta to the Great Lakes and Midwest over the Lakehead Pipeline right-of-way 
which now carries crude oil to Northern Tier and Chicago refineries and 
is phasing down deliveries. 

In summary, it appears that the coal transportation issues that become 
important over the next few years, and the impact of their solutions, cannot 
be conclusively weighed or decided until some basic policy questions are 
answered that establish the relative user economics among coals of dif- 
ferent types from different domestic sources. 

3.6.1.4. Nuclear Fuels and Electricity . As was noted in the first 
volume of this study (1.5.3., pp. 395-398), the high energy content and 
small size per shipment of nuclear fuel materials has led to a markedly 
different pattern of movement compared to other fuels. The variation in cost 
of nuclear materials movements as a function of distance is small compared 



543 

to those oi other fuels or electricity. It is the fixed costs, those 

which must be borne whether the shipment goes three thousand miles or 

three city blocks, that create most of the expense of moving nuclear materials, 

and in most segments of the nuclear fuel cycle those expenses are quite 

smal 1 . 

The exceptions are in the transportation of spent nuclear fuel and 
of high-level radioactive waste. These highly radioactive materials require 
large, heavily shielded casks that can provide protection for the material 
in case of accidents and can dissipate the heat produced by the radioactive 
contents. The issues involved concern the use of overweight trucks to carry 
the heavy shipping casks (3.1.2.) and the shipping of such materials via 
railroad (3.1.6.). In addition, the use of plutonium in the nuclear fuel 
cycle — an option that has been "indefinitely deferred" by the Carter 
Administration — would require the protection of those segments of the fuel 
cycle in which plutonium was vulnerable to hijacking by terrorists or crim- 
inals . 

The affected transportation links include the shipment of pluto- 
nium from a reprocessing facility to a fuel fabrication facility, and, to 
a lesser extent, shipment of fuel containing plutonium to individual nuclear 
reactors. The elaborate and expensive equipment and precautions involved 
in safeguarding shipments of plutonium could be a significant economic 
factor in transportation of nuclear materials, since the links between fuel 
fabrication facilities and reactors are long and diffuse. The safeguards 
problems does not exist at present, since the fuel used by currently operating 
reactors does not contain sufficient concentrations of nuclear material to be 
used as explosives and so would not be useful to terrorists. 



544 

The safety aspects of shipping spent nuclear fuel and high-level radio- 
active wastes are the subject of considerable controversy. The materials 
transported in these links in the fuel cycle are highly dangerous and the 
controversy revolves around the precautions necessary to reduce adequately 
the likelihood of a large release of these materials to the environment 
in the event of an accident. 

Electric transmission is the opposite of nuclear fuel movements in 
average length of shipment. Only a few multi-State flows take place; 
most are relatively local. The unification of the Nation's transmission 
system into a national power grid (3.1.13.) would not begin a pattern of 
massive and continuous long distance movements of electricity. Rather 
it would provide greater security and load-sharing ability to counter 
localized problems such as lightning shutting down transmission lines or 
fuel interruptions shutting down generating plants (3.1.15.). 

3.6.2. Summary and Analysis by Mode . 

3.6.2.1. Pipeline . Pipelines are essentially the only carrier of 
natural gas, the major mover of crude oil, the primary method of moving 
lighter petroleum products in bulk over a substantial distance, and a 
feasible method of moving coal in the form of slurry. With this sort 
of involvement in energy transportation, it is little wonder that pipe- 
lines should be dealt with or affected by the resolutions of almost half 
of the issues described in this volume. 

Pipelines are the most efficient and economical method of moving liquids 
or gas over land, and also the least flexible in terms of route. The issues 
in this volume deal with construction of new pipelines, ownership and opera- 
tion of pipelines, regulation of pipelines, competition with and among 



545 

pipelines, rates and financing of pipelines, security of pipelines, and 
conversion of pipelines from one substance to another. 

New pipelines are considered for carrying natural gas from Alaska (3.2.6.), 
Alaskan crude oil from the West Coast to the Midwest (3.2.1.), natural gas 
from Mexico (3.3.6.), coal slurry from the western and possible also the 
eastern coal fields, and for additional Alaskan oil. Only the last of these 
is an increase in capacity where there is current movement — all the others 
are new movements, new primary connections of areas of energy supply with 
areas of energy demand. 

The regulation and modes of operation of all types of pipelines are in 
flux. Gas pipelines, reeling from the effects of the natural gas shortage, 
have been forced into unprecedented arrangements for obtaining gas supplies 
on a short term basis, carrying natural gas purchased directly by industrial 
customers, delivering natural gas to or receiving gas from other pipelines 
to meet critical shortages, and depreciating their investment over a much 
shorter period of years than they hope they will be useful (3.1.10.). Oil 
pipelines, long the target of moves toward vertical divestiture in the oil 
industry, now find their regulation shifted to a new agency, which may change 
its form and content (3.1.11.). Coal slurry pipelines are about to be born 
into a regulatory environment different from the others, if they are born 
at all (3.4.6.) If these issues suggest anything, it is that the pipeline 
industries of the future may be as changed in ownership and regulation 
as they are in pattern of movement. 

Only in natural gas have pipelines no common competition, and in certain 
instances, such as the Alaska gas proposals, there is competition with proposals 



546 



I 



to move gas as LNG (3.2.6.). The tanker competition to oil pipelines that 
turned the creation of the Colonial pipeline into a holy war that the losing 
maritime interests are still waging has heated up again because of the propoe 
conversion of the Florida gas line to petroleum products (3.1.14.). A new 
concept in tank-car unit trains is alleged to have economics equal to a 
250,000 barrel per day oil pipeline (3.2.1.). And proposed coal slurry 
pipelines obviously face the strongest array of competing modes yet. 
Generally conceded to be less preferable than waterway shipments, coal slurn 



lines may also be beaten out economically by unit trains, certainly over 
some routes, and are less flexible than railroads over all routes. 

Part of the reason for pipelines giving stiff competition to other modes 
is that their costs are largely front-end costs; operating costs are light 
compared to initial costs. Existing pipelines have thus been able to 
maintain and strengthen their advantages, while other modes are subject 
much more to the ravages of inflation. New pipelines are not so lucky, 
however, and their cost has skyrocketed. It was so high in the case of 
the Alyeska pipeline that the tariff for oil transportation across the 
State of Alaska alone will be more than twice the wellhead value of the 
oil in Alaska when the pipeline was first proposed. It is so large that 
it pinches the State of Alaska's royalty by reducing the possible wellhead 
revenues when subtracted from world price levels (3.2.5.). And the Alaska 
Highway gas pipeline is certain, if it is built, to replace the Alaska oil 
line as the most expensive private project even undertaken. Can the money 
to build it be raised? Certainly not unless investors are assured that the 
natural gas it carries will be sold. But the cost of the pipeline itself m<' 
price the gas out of the market, especially if it is priced incrementally 



i 



547 

to the user. And what will coal slurry rates be and investment costs total? 
This is a great unknown, making firm judgments of relative transportation 
economics impossible. The proposed coal slurry pipelines may meet the fate 
of one of the two existing pipelines — to be completed and launched into 
operation, only to be driven from business by new found economics in rail 
movement (see 3.4.4.). Will investors in coal slurry pipelines be able to 
protect themselves from this fate by means of firm throughput contracts 
under the legislation authorizing eminent domain? If not, will they still 
invest? Are coal slurry pipelines to be a club in the hands of coal shippers 
that will never be used if it can be lifted, but will always be needed if 
it can't? 

One possibility for maintaining economic viability appears to be to 
take advantage of the large fixed investment in a pipeline by converting 
an old pipeline to a new purpose. Practiced sporadically throughout pipe- 
line history, conversions and reversals of pipelines have reinvigorated 
many systems left underutilized or abandoned by the circumstances of sup- 
ply and demand. Two current examples are the PACTEX proposal (3.2.1.) and 
Florida gas proposal (3.1.14.) The potential for such conversions to coal 
slurry may be quite significant (3.1.16.). 

In summary, the general trends that can be discussed for pipelines 
as a mode of energy movement are the end of the era of capacity growth 
along many of the current major pipeline corridors, the establishment of 
flows of energy materials from new supply regions in new corridors, 
some major rethinking of regulatory and operational practices, the pos- 
sible birth of a new pipeline industry related to coal, and attempts to 



548 

preserve the greatest value of existing systems, even through conversions 
and renewals. 

3.6.2.2. Railroads . The railroad industry will be affected in important 
ways by the resolution of energy transportation questions. This venerable 
mode of transportation, older than pipelines, tankers, or trucks, is perhaps 
"younger" than these modes in the extent to which new technologies and develop- 
ments could open up new functions for it. 

For example, the adoption of new traffic management capabilities can 
multiply the capacity of a given stretch of track (3.4.2.) and the develop- 
ment of unit trains of interlocked tank cars may bring new economies to rail- 
road movement of liquid fuels that would enable railroads, with their better 
geographic flexibility, to compete with pipelines and water carriers, which 
have enjoyed better economics because of volume (3.2.1.). 

The new emphasis on coal, the fuel that is carried more by railroads 
than any other mode, and is the most important commodity to the railroads, 
can be the key to a renaissance of the rails, in combination with the 
new capabilities. 

The railroads are in need of a renaissance (3.1.7.). Many roads are 
threatened with bankruptcy; few are doing as well as the average of U.S. 
companies. Track has degenerated as maintenance and investment has been 
deferred. The potential traffic from new energy movements have the potential 
to turn this bleak situation around. 

There are possible obstacles in this road to recovery and there are 
also possible aids. 

The possible obstacle which the railroads fear the most is that of coal 
slurry pipelines (3.4.6.). The railroads claim that this would "skim the 



549 

cream" of the coal traffic, taking and tying up the long-term, large volume, 
dependable business which could form the foundation for new investments and 
economic recovery. This threat has been most widely perceived by railroads 
in the West, spurred by the projections of growth in coal output there. It 
may be that the weaker eastern railroads have the most to fear from coal 
slurry pipelines, however (3.1.16.). 

On the other hand, the competitive position of eastern railroads would 
be aided by the imposition of waterways user charges on their barge competi- 
tors (3.1.9.). Railroads in general may be able to improve their competi- 
tiveness through regulatory change to enable them to obtain long term com- 
mitted traffic (3.4.4.). 

There will be higher costs to pay for environmental and public safety 
goals: to minimize the impact of increased traffic on local residents 
(3.4.3.); to preserve the public from hazardous materials in transit (3.1.8.); 
or possibly to become involved in the movement of certain nuclear materials 
(3.1.6.). 

By the end of the century, the railroads might have returned to prosperity 
on the coattails of massive energy movement traffic and be once again an 
integral part of the energy cycle in the United States; or they might be 
a vestige of their current strength, bankrupt, hauling coal only where there 
is no feasible alternative. The resolution of the key coal policy issues 
mentioned above will have much to do with the future of the railroads. 

3.6.2.3. Truck . All fuels are transported at least to some extent 
by truck. Natural gas, carried in insulated tank trucks as LNG to local 
peaking plants, is the fuel least dependent on trucking — such shipments 
are very small in volume compared to overall gas movement. Oil and coal 



) 

550 

depend on specialized trucks for short range movements. For oil, there are 
truck movements from the refiner or distributor to the marketer or final 
consumer. Almost all petroleum products are carried in a truck at some j 
point before their consumption. Coal is carried to water or rail loading 

! 

points, or to consuming plants, from the mine, and this is a vital part 

of coal movement. Finally, essentially all movements of nuclear fuel materials 

are carried in special containers by truck. 

Despite this significant traffic, the fortunes of the' trucking industry 
generally do not depend on energy transportation, as do those of pipelines || 
and the railroads. Trucks are now the major mode of intercity shipment of 
most commodities and products. Nor are trucks threatened by competition 
from alternative modes of energy movement, as the other modes are, because i 
the movements, they engage in are largely those for which they are uniquely 
qualified. There are exceptions to this in the minor aspects of long-haul 
movement of LP gases, which pipelines or rails can also handle if the quantity 
is large enough, and in nuclear waste transportation (3.1.6.). But only 
trucks can handle the small, sporadic, and short movements required in dis- 
tribution of petroleum products, movement of coal from small mines to central 
loading points, or gathering of crude oil from stripper wells. And only 
, trucks are economical for most of the movements in the nuclear cycle because 
of their small current quantity. 

The energy transportation issues related to trucking thus do not 
concern the strategic aspects of large-volume interregional movement of ;| 
energy or new departures in energy transportation. Instead they concern 
the economics and impacts associated with existing patterns. The one exception 
to this general rule may be the potential for expansion of truck movement 



of LNG. 




551 

Perhaps the most critical issue with regard to trucking of petro- 
leum products is that of the variety of weight and size limits in effect 
which limit the volume of material that can be handled (3.1.2.). A 
marked increase in the limit might extend the distance at which trucks 
are viable competitors in energy movements, or make trucking somewhat 
less expensive by increasing the number of delivery stops that could be 
made per trip (3.1.2.). The regulations for hazardous materials shipment 
are not currently being challenged, nor are they apparently being stringent- 
ly enforced (3.1.8.), so this remains a potential issue for truck movements. 

In the coal area, the key issue is that of maintaining the poor secondary 
roads over which coal trucks travel in Appalachia (3.1.4.), and other areas 
where economics make trucking the preferred method of movement. A change 
in the weight and size limits would change the range and economics of truck 
movement of coal as well as oil. 

In the nuclear area, the critical issue would be the safeguarding of trucks 
carrying plutonium nuclear materials which have potential for weapons production, 
in the event that plutonium recycle is adopted, and protection of the public 
from accidental contamination or exposure to dangerous radioactive substances 
(3.1.5.). 

A general issue is the fuel efficiency of truck movements. All the other 
energy moving modes are more fuel efficient, but again they could not re- 
place trucks for reasons of capital-insentiveness , shipment size and distance, 
and practicability. Nonetheless, improving the fuel efficiency of truck 
movements of energy materials is a laudable goal, and might occur as a part 
of improvement of truck fuel efficiency generally (3.1.3.), although current 
proposals would apparently not adopt standards affecting such trucks. 



552 t 

Summarizing, the issues related to energy transportation which concern 
trucking are related to current movements of fuel, and not as much to the 
new movements of fuel from Alaska, the western coal fields, or overseas. 
Nor do they relate to competition between trucks and other potential modes 
of transport — by and large, trucks are moving fuel where only they can 
suffice by reasons of cost, distance, and quantity to be moved. 

3.6.2.4. Water Carriers . Water carriers of energy can be clearly 
divided between those which operate on the inland waterway system, and 
those which ply the coastal and international shipping lanes. The issues 
which relate to water movement can be similarly divided: none of the key 
issues which affect barges and inland waterway operators also affect tan- 
kers and international shippers, and vice versa. 

Unquestionably the major issue confronting inland waterway traffic is 
that of waterway user charges (3.1.9.). Requiring its users to finance 
the further maintenance and development of the inland waterway system 
will markedly affect the economics and thus extent of its use. The 
resolution of the user charge question appears to be hand-in-hand with the 
resolution of the question of whether Lock and Dam # 26 will be reconstructed 
to facilitate traffic to the upper Mississippi (3.4.5.), a question which 
may not have major energy transportation significance for coal but may af- 
fect movement of oil to the upper Midwest. 

The level of competition between waterways and railroads and, to a lesser 
extent, between waterways and pipelines will change if a waterways user 
charge increases the cost of that mode to the shipper significantly. Be- 
cause of current investment and the momentum of current practices, it is 



553 

not likely that ongoing movements will shift dramatically from the water- 
ways to other modes. But future movements — expansion of coal traffic 
particularly — may be substantially different if the user charges reduce the 
barge's economic advantage for given movements, or make rail or pipeline 
movements economically competitive. Modal choices being faced now are 
handicapped by the uncertainties about whether use charges will be imposed 
(although it appears that they will) and what their effects will be on water- 
way economics. 

Ocean transportation of energy also faces some critical economic 
uncertainties. One is whether or not deepwater ports will be built that 
allow the U.S. to capitalize on the economies of scale offered by the super- 
tankers that cannot now utilize U.S. ports (3.3.1.). The resolution of this 
issue will affect not only import costs, but also the utilization of coastal 
harbor facilities and the pattern of crude oil flow inside the U.S. 

Another uncertainty is the extent to which security or other motivations 
will prompt the U.S. to require the use of U.S. flag vessels for oil 
imports. Such a requirement would alter the economics of oil movement 
(3.3.10.). An action in the opposite direction would be the allowance 
of foreign flag tankers to engage in U.S. coastal trade (3.2.3.). 

Competition with ocean going vessels from other modes is rare at the 
international level because there are usually no practical alternatives. 
But coastal trade must compete with other modes. The competition between 
coastal tankers and pipelines has been heated, and ocean carriers have 
so far been losing. The selected route for Alaskan natural gas was an 
overland pipeline rather than LNG transshipment to the West Coast (3.2.6.). 
The Alaskan oil surplus appears more likely to be resolved in the long 



554 



run by pipeline than tanker 



solutions, although tankers are supply 



mg 



the short-run solution and 



may provide part of the ultimate solut 



ion 



(3.2.1.). A pipeline which was built to carry natural gas now may be converted 
to petroleum products, taking the traffic from coastal shippers (3.1.14.). 
The transportation planning that is being conducted with regard to the possible 
use of the Strategic Petroleum Reserves is weighing tankers against pipelines 
for use as the distributing mode to certain regions (3.3.3.). 

Numerous issues relate to the security and safety of ocean shipments 
of energy. New requirements for anti-pollution practices and investment 



may change the operations and economics of water movement (3.3.2., 3.3.7.) 
whether national or international in origin. Theoretically catastrophic 
accidents involving tanker-borne LNG or LPG pose possible constraints, al- 
though the issue has been subject for wide discussion in regard to the 
former (3.3.8.) and has drawn little attention in connection with the 
latter (3.3.9.). Finally, the vulnerability of tankers to hostile actions 
adds other considerations to their use, although this factor can make 
little difference where there is no alternate mode, as in most international 



shipments (3.3.5.), and has already had significant results in domestic 



oil commerce. 

The likelihood of a continuing rise in oil imports over the next few 
years and a major role for imported energy indefinitely promise continued 
use of tankers. What may change is the economics of this use, based on 
the size and nationality of the ships and the safety and environmental 
standards they may be required to meet. 




555 

3.6.3. Additional Analysis and Conclusions 

Obviously, there are other ways in which the issues described in 
this volume could be integrated and analyzed than merely by fuel and 
by mode of transportation. Two others avenues which might be fruitful would 
be to look at the energy transportation issues from a regional perspective 
or to look at them from the perspective of congressional activities and 
priorities. 

Because so many of the energy transportation issues are geographical- 
ly specific, it is obvious that different regions of the United States 
would have different assessments of them and their importance. The 
West Coast has, for example, very little involvement in the coal move- 
ment issues, but critical involvement with all of the issues related to 
Alaska. The Northeast, on the other hand, is the region least directly 
affected by Alaskan energy transportation questions, but is vitally con- 
cerned with LNG imports, nuclear materials movement, tanker safety, and 
the effects of eastern coal production on the railroads of the region. The 
Northern Great Plains and Great Lakes area is most affected by the issues 
surrounding movement of western coal, but also will be importantly in- 
volved in both Alaskan oil distribution and Alaskan gas transmission. 
The Southeast is most concerned about eastern coal movement, waterway 
user charges, and the economic and regulatory fate of oil and gas pipelines. 
The Southwest and Gulf region is deeply involved in the issues concerning 
domestic oil and gas transportation by pipeline, and also with deepwater 
ports. Western coal transportation may have the Gulf region as a prime 
target, and LPG and Mexican gas imports may also focus there. The varying 



556 

regional interests in these issues may affect the speed and forums of 
the approaches taken to them. 

The congressional interest in many energy transportation questions 
is well formed. Coal slurry pipelines and waterway user charges are two 
issues Congress may act upon before this volume is published. Recent and 
decisive action has taken place in the areas of cargo preference and Alaskan 
natural gas, and other transportation issues identified here are subsumed 
in larger questions facing Congress, such as nuclear materials safeguards 
in the debates over the plutonium recycle program, natural gas pipelines 
in the debate over the natural gas portion of the National Energy Plan, 
and Lock amd Dam # 26 in the debate over users charges. Other issues 
have not as yet come to the fore in congressional deliberations, but many 
arise soon. 

A key factor in the congressional resolution of these issues will be the 
extent to which they can be considered in an overall context. If each issue 
is considered and disposed of on its own, in a vacuum, rather than put in 
relationship to the other issues and overall energy policy, the quality of 
the resulting decisions may suffer. For example, it is not clear that competi 
tion among all alternative modes for handling coal is being considered in the 
debate over waterway user changes or coal slurry pipelines to the extent 
necessary to prevent unintended effects, - It is not clear that the question 
of deepwater ports and their affects on the distribution of imported oil is 
being considered in conjunction with questions of the Alaskan oil distribution 
question. It is not clear that in setting air quality standards that would 



557 

determine coal usability, Congress realized it was also making major changes 
in the future patterns of coal development and transportation. Nor is it 
clear that sufficient thought to future needs was given when it was decided 
to send Alaskan oil first to the West Coast. 

One goal for Congress may therefore be to put each of the energy 
transportation issues into the context of the others and general energy 
policy. Although this volume may help to some extent by combining 
descriptions of these issues in one place and providing some integrating 
material from differing perspectives, this volume was not intended to 
provide the kind of quantitative analysis that would be required to make 
informed decisions about multiple trade offs. 

It may even be, at one extreme, that a national energy transportation 
policy would be appropriate, stipulating the optimum combinations of fuels 
to be used in various regions, their sources, and the modes by which they 
are brought, all internally rationalized for fuel costs, transportation 
economics, risks, and use considerations related to environmental and invest- 
ment factors. Perhaps current ad hoc energy transportation decisions could 
be combined and coordinated to the point that California's current dilemma 
regarding Alaskan oil transshipments could be weighed against future 
availability of foreign LPG , LNG , Alaska coal, and Mexican gas; or perhaps 
questions surrounding the Gulf region's access to Western coal can be 
combined in our overall equation of energy supply, demand, and transportation 
with considerations of interstate gas flows and oil imports. Perhaps such 
a quantitative analysis would reveal key areas for expansion of transportation 



558 

capacity in the future or need for development of currently unpracticed 
but possible transportation technologies such as tank car unit trains. 

Although such a quantitative analysis and attempt to think out a 
national energy transportation policy might be fruitful, on balance it is 
unlikely that "energy transportation" will become a central organizing con- 
cept for energy policy formation. The logistics of energy have always tended 
to be derived from the basic supply and demand factors, and seldom have 
supplies and demands been consciously meshed by consideration of the most 
appropriate logistical option. The result has been an energy transportation 
system with multiple incongruities, overlaps, and poor interfuel or inter- 
modal rationality. Nonetheless, an energy transportation system without such 
inconsistencies could not be workably imposed on the current pattern of source 
and uses, because of the inertia of the current system and the vast conversion 
expenses that would be entailed for both users and transporters. It would 
only be feasible to attempt to guide future energy decisions so that, 
among other things, additional energy transportation inconsistencies and prob- 
lems were not created. 

A national transportation policy exists, and a national energy policy is 
being worked on. It may be that a coherent national energy transportation 
policy, if it is not created anew, could be created at the junction of the 
two larger policy forming processes. If this could happen, there is no 
current sign that it is. The current attempt at a national energy policy 
in particular was conducted under great time constraints and is alleged 
to have been deficient in its recognition of factors and influences external 
to central energy considerations. Without overt coordination between the 



559 

policy planning entities, it is unlikely that the resulting energy transportation 
policy, stated or de facto , would be better coordinated. 

Sumnarizing, the central conclusion for the purposes of Congress is that 
the continued consideration of energy transportation issues in an ad hoc 
manner is unlikely to lead to an energy transportation system any more 
rational than the current one, with seemingly wise policy decisions on one 
issue resulting in unforeseen impacts elsewhere. On the other hand, a 
comprehensive national energy transportation policy is not being worked on 
now, could only be prospective, and is unlikely to emerge without a deliberate 
effort from separate ongoing national transportation policy and national 
energy policy processes. 

What is then the status quo? The effect of each of these issues being 
unresolved, or being resolved piecemeal without references to the others 
and to overall policy, is to create uncertainty among the actors and potential 
actors in the energy transportation area. Investors do not know whether 
pipelines can be built or sustain themselves over their useful lives, whether 
railroad maintenance would be a profitable investment, whether deepwater 
ports will eliminate small tankers in U.S. waters, or whether the cheapest 
available fuel to a given region will be solid, liquid, or gaseous. This 
uncertainty in turn makes participants more tenacious in their grip on 
the status quo, exacerbating the political tensions involved, and delaying 
solutions to related problems. 

This may perhaps provide a key to prioritizing these issues for a solution: 
those whose solutions which would remove the greatest amount of uncertainty with 
regard to future energy movement patterns and economics are those which 



560 

should perhaps be addressed first. Hopefully, the treatments of these issues 
in this volume may provide some insight as to the incertainties created in 
each area to aid in such an identification of priorities. Hopefully, also, 
correctly prioritizing the issues to be resolved into an appropriate 
sequence would go part way toward the rationalization of the issues and their 
solutions that could only be fully achieved with a comprehensive energy 
transportation policy. 

O 



UNIVERSITY OF FLORIDA 




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